1

Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report 

06/10/13 

Entergy has reviewed the comments provided by EPA Region 6 on March 6, 2013 and appreciates the 

opportunity to provide the below response. To simplify the format of this response, we have included 

each of EPA’s comments, followed by our response. Submitted concurrently herewith is a revised FiveFactor Analysis (FFA) incorporating several revisions as discussed below. 

SO2 BART

x EPA Comment 1 - A BART evaluation requires that, “in analyzing the technology you take into 

account the most stringent emission control level that the technology is capable of achieving” (70 

FR 39166). ADEQ should demonstrate this requirement has been met. In particular, the BART 

report for Entergy White Bluff states that wet scrubbers can achieve up to 95% control efficiency 

at Units 1 and 2. It is also stated that discussions with vendors suggest that although a wet 

scrubber may be able to achieve up to 97% control at units burning higher sulfur coal, this may 

not be achievable for the low sulfur coal typically combusted at Units 1 and 2. The BART report 

should include documentation from the vendor to corroborate this statement. Furthermore, 

section 5.4 of the BART report indicates that semi-dry scrubbers were evaluated at an outlet SO2

emission rate of 0.06 lb/MMBtu and wet scrubbers at an outlet SO2 emission rate of 0.04 

lb/MMBtu. In section 5.4 it is stated that this represents 95% removal efficiency for the dry 

scrubber option and 97% removal efficiency for the wet scrubber option when applied to the 

units’ currently allowable SO2 emission rate of 1.2 lb/MMBtu. Considering that the 2001-2003 

average SO2 emission rate is 0.81 lb/MMBtu at Unit 1 and 0.79 lb/MMBtu at Unit 2 (based on 

information recently provided by Entergy), it appears that the actual removal efficiency 

evaluated for the two control options at Units 1 and 2 is less than 95% for dry scrubbers and less 

than 97% for wet scrubbers. Based on the annual SO2 emissions reductions expected to result 

from each control option (as shown in tables 5-7 and 5-8), it appears that dry scrubbers were 

evaluated at 91.5% removal efficiency for Unit 1 and 90.5% for Unit 2 while wet scrubbers were 

evaluated at 94.3% removal efficiency for Unit 1 and 93.7% for Unit 2. ADEQ should ensure 

that the requirement to evaluate the most stringent emission control level the technology is 

capable of achieving has been satisfied. 

Entergy Response – Entergy has evaluated available SO2 emission control technologies and 

believes that the level of control considered within the February 2013 FFA (and the June 2013 

revised FFA) represents the most stringent level of control for each technology for the operating 

conditions which exist at the White Bluff plant. It is also important to consider the inherent 

variability of emissions over time and allow for a reasonable compliance margin in determining a 

potential 30-day average emission limitation for evaluation in the FFA process. 

Entergy commissioned a study in 2008 from Sargent & Lundy (S&L) to compare the control and 

cost effectiveness of dry versus wet flue gas desulfurization (FGD) technologies. A copy of this 
2

study was previously provided along with our revised BART FFA submitted in 2008. For 

reference, a copy of this study is included with this response as Attachment D. It should be 

noted that the financial information included in this study is out-of-date and is not consistent 

with more recent information which was relied upon in the 2013 FFAs. 

In this study, S&L indicates that typical control efficiencies achieved by dry FGD range from 

85% - 95% in real-world applications1, depending on the dry FGD inlet SO2 concentration. A 

chart is provided of typical SO2 reduction efficiency as a function of inlet SO2 emission rates (lb 

SO2/MMBtu)2. Based on S&L’s data, the maximum SO2 control efficiency (95%) is achieved at 

an inlet SO2 emission rate in the range of 1.8 to 3 lb/MMBtu). Expected control efficiencies for 

inlet SO2 emission rates similar to those at White Bluff Units 1 and 2 (0.6 to 1.2 lb SO2/MMBtu) 

are in the range of 90-93%. This is consistent with the control efficiency evaluated within the 

2013 FFA for semi-dry scrubbing, as documented in Tables 5-7 and 5-8. It is noted that the 

control efficiencies calculated by EPA in its comments are based on a mix of the post-control 30-

day average emission rate and the pre-control 3-year average emission rate over the baseline 

period. An “apples to apples” calculation based on the maximum 30-day average emission rate 

during the baseline period (0.81 lb/MMBtu for Unit 1 and 0.79 lb/MMBtu for Unit 2) and the 

post-control 30-day average emission rate (0.06 lb/MMBtu for each unit) results in control 

efficiencies for semi-dry scrubbing of 92.6% for Unit 1 and 92.4% for Unit 2. 

For wet FGD, the S&L study indicates that control efficiencies in the range of 95-99% are 

achievable for units burning medium-to-high sulfur coals and efficiencies of 93-95% achievable 

for units burning low-sulfur coals3 such as that typically utilized by White Bluff Units 1 and 2. 

As with dry FGD above, EPA is mixing 3-year average and 30-day average SO2 emission rates 

in calculating the control efficiency evaluated for wet FGD. Based on the maximum 30-day 

average emission rate during the baseline period for each unit, and the post-control 30-day 

average emission rate of 0.04 lb/MMBtu for wet FGD, the 2013 FFAs consider wet FGD at a 

control efficiency of 95.06% for Unit 1 and 94.9% for Unit 2. This is consistent with the 

information provided by S&L, and represents the most stringent level of control achievable by 

this technology for the operating conditions present at White Bluff Units 1 and 2. 

As outlined above, Entergy is considering the most stringent level of control achievable for Units 

1 and 2 at White Bluff. 

x EPA Comment 2 - The executive summary (section 1) of the BART report states that Entergy 

has concluded that the installation of a semi-dry scrubber and baghouse is BART for SO2 for 

both Units 1 and 2. However, the SO2 controls evaluated in the BART report are wet scrubbers 

 

1

 S&L Wet vs. Dry FGD Technology Study (October 2008), pg. 2-3, attached as Attachment D. 

2

Id. at 2-3, Figure 2-1 

3

Id. at 2-13. 
3

and semi-dry scrubbers, and no mention of a baghouse is made in the body of the BART report. 

The cost evaluation of the dry scrubber option (in Appendix A) contains line items related to the 

O&M costs of the baghouse, but there does not appear to be a line item for the baghouse capital 

costs. Please specify whether the dry scrubbing technology evaluated and selected as BART is 

NID or some configuration of SDA. 

Entergy Response – The semi-dry scrubbing evaluated and selected as BART is based on a 

SDA system. However, Entergy is exploring both NID and SDA as potential technology 

selections for SO2 control. Both technologies are capable of similar levels of SO2 emission 

reduction. Either technology may be ultimately selected by Entergy if the proposed SO2 BART 

determination is approved by ADEQ. 

The semi-dry scrubber cost estimate includes a baghouse. The cost estimate utilized for the 2013 

FFAs was based on a vendor quote (Alstom) for an SDA system, including a baghouse. This 

quote was obtained by Entergy in 2011 and was adjusted to 2012 dollars for the purposes of the 

2013 FFAs. Additional details regarding the cost estimate for the semi-dry FGD system are 

included with this response. 

x EPA Comment 3 - In the cost evaluation of SO2 controls Entergy assumed a 15 year equipment 

life for both wet and semi-dry scrubbers, based on a misinterpretation of the EPA Control Cost 

Manual (CCM).4 EPA believes that 30 years is the more appropriate equipment life for 

scrubbers. If Entergy believes that the remaining useful life of the boilers affects the BART 

determination, then an equipment life less than 30 years may be assumed, but this would require 

a federally enforceable restriction preventing further operation of the boilers by a date certain. 

Scrubber vendors indicate that the lifetime of a scrubber is equal to the lifetime of the boiler, 

which in some cases easily exceeds 60 years. The typical life for a scrubber is reported as 30 

years in published papers and standard cost estimating handbooks. Since the capital costs are 

annualized over a period of time equal to the anticipated equipment life, and then added to the 

annual O&M costs to obtain the total annualized costs, the two SO2 control options evaluated 

will be more cost effective than what is estimated in Entergy’s cost evaluation if a 30 year 

operating life is assumed. 

Entergy Response – The assumed equipment life has been revised to 30 years. This change is 

reflected in the costing tables presented in section 5 of the June 2013 revised FFA. Please note 

that the capital recovery period does not affect the outcome of the BART determination in the 

June 2013 revised FFA. 

x EPA Comment 4 - In section 5.4.1, it is stated that the capital and O&M costs used in Entergy’s 

cost effectiveness calculations for the wet scrubber option are based on vendor estimates for a 

 

4

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002; see

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf. 
4

system designed to achieve 97% control (0.06 lb/MMBtu) for an inlet SO2 rate of 2.0 lb/MMBtu, 

and that the cost for a system designed to achieve an emission rate of 0.04 lb/MMBtu for an inlet 

SO2 rate of 1.2 lb/MMBtu would be approximately 5-6% higher. It does not appear that Units 1 

and 2 have historically burned coal containing 1.2 lb/MMBtu SO2. To properly evaluate costeffectiveness, controls should either be designed to burn coal with the same sulfur content as has 

been historically used at the units (2001-2003), or if the controls evaluated are designed to burn 

coal with a higher sulfur content than has been historically used at the units, ADEQ should 

ensure that the baseline is raised to correspond with the sulfur content of the type of coal the 

scrubber has been designed to burn. 

Entergy Response – Entergy does not believe it is necessary to re-evaluate the selected 

technology nor to adjust the baseline as the FFA was developed with consideration of the sulfur 

content of the type of coal historically burned at the facility as well as that for which a scrubber 

would be designed. As both units are subject to an emission limit of 1.2 lb SO2/MMBtu, it is not 

possible for the baseline emission rate to exceed this level. 

In initiating the effort to develop an updated FFA (from 2008) for Units 1 and 2 at the White 

Bluff facility, Entergy considered both semi-dry and wet FGD to be equivalent technologies and 

intended to evaluate only semi-dry FGD as the most stringent level of control available for SO2

emissions from Units 1 and 2. During Entergy’s efforts to prepare an updated FFA, feedback 

was received that EPA Region 6 believed that wet FGD technologies were capable of a greater 

level of control than that achievable by semi-dry FGD technologies, and that wet FGD should be 

considered separately in a proper FFA. In order to address this concern, Entergy conducted a 

review of existing studies of available SO2 control technologies, and held discussions with S&L 

on this topic. Based on this review, Entergy determined that a wet FGD system may be able to 

achieve a slightly higher level of SO2 control for Units 1 and 2. Entergy has received no 

guarantees to this effect, but this assumption was utilized for the purposes of the February 2013 

FFA. In order to facilitate Entergy’s ability to consider wet FGD within the FFA, a decision was 

made to rely upon existing wet FGD cost estimates for Units 1 and 2. Since no cost estimate was 

available specific to an outlet emission rate of 0.04 lb/MMBtu, S&L indicated that an existing 

available estimate for 97% control at an inlet SO2 emission rate of 2.0 lb/MMBtu would be 

reasonably representative of the costs expected for a scrubber designed to achieve an outlet 

emission rate of 0.04 lb/MMBtu for coals typically combusted at White Bluff Units 1 and 2. 

On this basis, Entergy relied upon this existing available cost estimate for the purposes of the 

FFA. As it is more difficult to achieve high levels of SO2 reduction at lower SO2 inlet emission 

rates, such as those observed on White Bluff Units 1 and 2 during the 2001-2003 baseline period, 

S&L estimated that a wet FGD system designed for an outlet emission rate of 0.04 lb/MMBtu 

would be 5-6% higher than the estimate which was used for the purpose of the FFA. This 

additional 5-6% was not added to the cost estimate used within the FFA, but was noted within 

the narrative of the document. Entergy believes the cost estimate utilized for the FFA represents 

a conservative estimate of the cost of a wet FGD system designed for an outlet SO2 emission rate 
5

of 0.04 lb/MMBtu for the units at White Bluff. A copy of the cost estimate utilized for purposes 

of the FFA is provided with this response (Attachment C). 

As Units 1 and 2 at White Bluff currently do not employ any post-combustion SO2 controls, 

Entergy primarily combusts low-sulfur coal in order to ensure an adequate margin of compliance 

with the existing emission limit of 1.2 lb SO2/MMBtu. Installation of post-combustion SO2

controls, as proposed by the 2013 FFAs, will allow greater control of the SO2 emission rate and 

may allow for greater flexibility in fuel supplies. The cost estimate utilized by Entergy for the 

purposes of the FFA was prepared by S&L in the course of investigating such potential options 

for an SO2-controlled operating scenario. 

x EPA Comment 5 - In section 5.6 the statement is made that EPA previously agreed that SDA 

technology is BART for White Bluff Units 1 and 2. The statement makes reference to a letter 

dated November 25, 2009, from Region 6 to ADEQ, in which comments were provided on the 

draft Title V/Prevention of Significant Deterioration (PSD) permit for White Bluff. In that letter, 

EPA agreed that dry scrubber technology is one of the SO2 controls generally accepted as BART. 

Although that statement, offered in another regulatory context, remains true, EPA action on a 

state’s BART determination can only be made via rulemaking after public notice and comment. 

Entergy Response – Entergy notes that the cited comment from the Nov. 25, 2009, letter was 

specific to Units 1 and 2 at White Bluff. The relevant statement reads as follows: 

Specifically, for Units 1 and 2, BART for sulfur dioxide (SO2) was determined to 

be the retrofit of a spray dryer absorber (SDA)/fabric filter dry flue gas 

desulfurization system. While we agree that this technology is BART for these 

two units, we do not believe that the emission rate of 0.15 pounds (lbs)/millions 

British thermal units (MMBtu) is BART.5

The 2013 FFAs submitted by Entergy propose semi-dry FGD (such as SDA) as BART for both 

Unit 1 and Unit 2, at a 30-day average emission rate of 0.06 lb SO2/MMBtu. This technology 

and emission rate is consistent with EPA’s statements in the November 2009 letter. 

x EPA Comment 6 - Entergy is proposing to use a semi-dry scrubber and a baghouse to satisfy 

SO2 BART at Units 1 and 2, which will involve replacing the existing ESPs with baghouses. 

Since this will likely result in a higher PM removal efficiency than currently achieved by the 

existing ESPs, ADEQ should re-evaluate the BART limits previously established for Units 1 and 

2 and ensure that the limits still meet the criteria of being the most stringent limit reasonably 

available. 

 

5

 Letter from Jeff Robinson, Chief, Air Permits Section, US EPA Region 6 to Thomas Rheaume, Air Permits Branch 

Manager, ADEQ dated November 25, 2009. 
6

Entergy Response – ADEQ’s previous BART determination for PM from Units 1 and 2 at 

White Bluff was approved by the EPA into the Arkansas SIP6. 

x EPA Comment 7 - The cost evaluations for SO2 controls included undocumented costs, line 

items that should be identified/explained, as well as some costs that are not allowed under the 

CCM. According to the CCM, AFUDC costs are not allowed in estimating capital costs for 

controls. In addition, for the semi-dry scrubber cost evaluation, please provide the following: 

o a breakdown of costs for FGD equipment, FGD materials, BOP equipment, and BOP 

materials; 

o please explain which line item(s) account for the capital costs of the baghouse; 

o the estimate should explain the need for the costs under FGD contractor contingency; 

o The estimate should explain what expenses are accounted for under BOP indirect costs, 

miscellaneous contractor labor, Entergy internal costs, and capital suspense. 

For the wet scrubber cost evaluation, please provide a breakdown of total equipment costs, 

purchased equipment cost, and direct annual costs. 

Entergy Response - 

AFUDC: 

Entergy disagrees with EPA that AFUDC should not be included as part of the costs of control 

technology. The CCM does not preclude inclusion of AFUDC and, indeed, the formula included 

in the CCM expressly includes AFUDC as a variable. The fact that the example used in the 

CCM “assumes” that AFUDC is zero does not reflect a reasoned decision to exclude AFUDC. 

The CCM expressly anticipates the inclusion of AFUDC where appropriate. Further, the CCM 

clearly allows the inclusion of interest costs associated with the control technology. AFUDC is 

nothing more that the interest expense on the investment in the technology that is incurred during 

construction, before the equipment is placed in service. For major control technology 

installations, such as scrubbers or SCR, the interest expense incurred during the 30 - 46 months 

of construction can reach $30 million to $60 million for a large unit. AFUDC simply includes 

the interest as part of the capital cost, which is standard accounting and rate-making treatment of 

such costs. 

Costs for Semi-dry Scrubbing: 

Contractor Costs

Entergy has revised the February 2013 FFA report regarding contractor cost for semi-dry 

scrubbing to reflect a 30-year equipment life. The revised report is provided under the same 

cover as this question and answer document. The following summarizes the iterative process 

Entergy followed for estimating the contractor costs for semi-dry scrubbing. 

 

6

77 FR 14675
7

In early 2009, S&L provided Entergy a line-itemed cost estimate that included contractor 

equipment, material, and labor costs for two semi-dry scrubbing systems. The total estimated 

contractor cost was $291,930,000. The itemized costs are provided in Table A-1 of Attachment 

A. Itemized baghouse costs were included. 

In December 2009, Alstom provided Entergy with a “Milestone Payment Schedule”. The 

payment schedule did not include itemized equipment cost, but; at the bottom of the schedule; 

the value of Alstom’s contract with Entergy to supply two semi-dry scrubbing systems 

($247,856,184) was specified. A copy of the payment schedule is provided in Attachment A to 

this response. Note that the total contract price for the two semi-dry scrubbing systems included 

in Alstom’s December 2009 payment schedule ($247,856,184) is less than the cost estimate 

provided by S&L to Entergy in early 2009 ($291,930,000). 

In early 2010, Entergy canceled the 2009 contract with Alstom for the supply of two semi-dry 

scrubbing systems. 

In 2010, Alstom informed Entergy that if Entergy subsequently were to continue with the 

project, the 2009 contract price of $247,856,184 would increase by 10%. For purposes of the 

BART analysis, Entergy relied on the lower contractor cost of $272,197,128 ($247,856,184 plus 

the approximately 10% increase). 

EPA asked for a breakdown of the equipment and material costs associated with the 

$272,197,128 estimated cost for the February 2013 FFA. Alstom did not provide such 

itemization. Thus, Entergy used the line-itemed cost information from early 2009 to estimate the 

line-itemed cost for the total estimated cost of $272,197,128. Entergy took the total cost of 

$272,197,128 and multiplied the total cost by the percentage of the total cost estimated for 

equipment, materials, and labor. Entergy based the percentages of the total estimated cost 

specific to equipment, materials, and labor on the early 2009 line-itemed cost estimate provided 

by S&L as shown in Table A-1 of Attachment A (equipment = 42%, materials = 11%, labor = 

47%.) This resulted in costs of $115,299,965 for equipment, $29,681,855 for materials and 

$127,215,308 for labor. 

Then, Entergy multiplied the estimated costs for equipment, materials, and labor by the 

percentage of the cost estimated for each line item represented in the early 2009 cost estimate 

provided by S&L. The percentages reflected in the early 2009 cost estimate were applied to the 

revised cost estimates for equipment, materials, and labor described above in order to obtain 

itemized costs that follow the itemization in the 2009 detailed estimate. The line item breakout 

is provided in Table 1. Note that the estimated cost of $272,197,128, which was utilized in the 

February 2013 FFA, is approximately 6.8% less than the early 2009 contractor cost estimate of 

$291,930,000 provided to Entergy by S&L.
8

TABLE 1. BREAKDOWN OF EQUIPMENT, MATERIAL, AND LABOR COSTS FOR SEMI-DRY 

SCRUBBING

Equipment Material Labor

2009 S&L Estimate Categorical Cost Percentages 42% 11% 47%

Applying percenages to 2010 Cost Estimate ($272,197,128) $ 115,299,965 $ 29,681,855 $ 127,215,308 

Equipment Cost

% of Total 

Equip Cost Material Cost

% of Total 

Material Cost Labor Cost

% of Total 

Labor Cost

UNIT 1 ABSORBER AREA $ 22,575,191 19.6% $ 958,795 3.2% $ 12,205,592 9.6%

UNIT 2 ABSORBER AREA $ 22,575,191 19.6% $ 863,640 2.9% $ 12,139,470 9.5%

REAGENT PREP SYSTEM $ 11,254,673 9.8% $ 9,062 0.0% $ 8,096,705 6.4%

WASTE RECYLING SYSTEM $ 4,443,550 3.9% $ - - $ 3,299,589 2.6%

COMMON STRUCTURES AREA $ - $ 2,157,741 7.3% $ 1,815,100 1.4%

REAGENT HANDLING SYSTEM $ - $ 226,558 0.8% $ - -

UNIT 1 FLUE GAS SYSTEM $ 225,752 0.2% $ 10,259,466 34.6% $ 15,931,715 12.5%

UNIT 2 FLUE GAS SYSTEM $ 225,752 0.2% $ 10,259,466 34.6% $ 15,931,715 12.5%

UNIT 1 BOOSTER FANS $ 5,361,608 4.7% $ - - $ 138,763 0.1%

UNIT 2 BOOSTER FANS $ 5,361,608 4.7% $ - - $ 138,763 0.1%

UNIT 1 NEW BAGHOUSE $ 20,693,925 17.9% $ - - $ 7,917,896 6.2%

UNIT 2 NEW BAGHOUSE $ 20,693,925 17.9% $ - - $ 7,917,896 6.2%

INSTRUMENTATION $ 1,888,791 1.6% $ - - $ 176,947 0.1%

MOBILIZE/DEMOBILIZE $ - $ 857,725 0.7%

OVERTIME $ - $ 12,068,691 9.5%

PER DIEM $ - $ 11,942,034 9.4%

FREIGHT $ 1,237,008 4.2% $ -

GENERAL & ADMINISTRATION $ 1,237,008 4.2% $ 5,545,880 4.4%

PROFIT $ 2,473,110 8.3% $ 11,090,828 8.7%

UNIT 2 BOOSTER FANS

UNIT 1 BAGHOUSE 

UNIT 2 BAGHOUSE 

SITE IMPROVEMENTS 

MECHANICAL MISCELLANEOUS 

PIPE RACK

DEMOLITION COSTS

ELECTRICAL 

Total Estimated Costs $ 115,299,965 $ 29,681,855 $ 127,215,308

Total Estimated Costs: Equipment, Material & Labor

Total Estimated Costs, Per Unit $ 57,649,983 $ 14,840,928 $ 63,607,654

Total Cost for Equipment, Materials, and Labor from 2009 Alstrom Cost Estimate with 10% Escalation $ 272,197,128

$ 272,197,128

BOP Costs 

In 2008, S&L provided information on the balance of plant (“BOP”) equipment, materials, and 

labor costs to Entergy. The breakout of the 2008 BOP equipment, materials, and labor cost is 

provided in Attachment B. In using the 2008 BOP costs as part of the cost estimate for semi-dry 

scrubbing, Entergy escalated the costs from 2008 dollars to 2012 dollars. 
9

TABLE 2: BOP EQUIPMENT AND MATERIALS SUMMARY, SEMI-DRY SCRUBBING

Cost Included in 

BART Submittal

Cost from 2008 

S&L Quote

Cost Based on 

Entergy Escalation 

of 2008 S&L Quote 

to 2012 Dollars

BOP Total Equipment Costs $ 49,632,641 $ 46,037,000 $ 3,595,641 

BOP Total Material Costs $ 52,928,270 $ 42,144,000 $ 10,784,270 

Please note that in reviewing the 2008 S&L data for this response it was discovered that the BOP 

costs presented in the February 2013 FFA as being in 2008 dollars were actually in 2012 dollars. 

Thus, the costs should not have been escalated from 2008 to 2012 dollars, as they were in the 

BART analysis. Entergy has revised the costing to subtract the extra $14,379,412 from the BOP 

costs. This revision is reflected in the June 2013 revised FFA. 

Contingency 

FGD contingency was calculated as 15% of the total FGD costs, and was included to account for 

change orders and risks such as regulatory, environmental (e.g. fly ash classification as a 

hazardous material) and underground interference that would have an impact on the baghouse or 

FGD structure. The CCM clearly allows for contingency costs on page 2-30, as long as in using 

the contingency factor no “double penalty” is imposed on the system. The CCM continues, “A 

contingency factor should be reserved (and applied to) only those items that could incur a 

reasonable but unanticipated increase but are not directly related to the demolition, fabrication, 

and installation of the system.” Entergy took this guidance into consideration when developing 

the contingency estimate. 

BOP Indirect Costs 

BOP indirect costs are costs associated with engineering, construction management, startup and 

commissioning and are estimates provided by the contractor. Miscellaneous contractor labor is 

inclusive of legal support, owner’s insurance, S&L engineering costs, and Entergy’s 

environmental permitting costs. Entergy internal costs include ESI labor, construction site labor, 

travel and loader costs. 

Capital Suspense 

Capital suspense is a distribution of overhead costs associated with administrators, engineers, 

and supervisors and includes function specific rates and A&G (Corporate Accounting) rates. 

Function specific capital suspense is dependent upon the personal hours allocated to a specific 

project for a time period. However, the percent of a total project that is dedicated to capital 

suspense is not a constant. Rather, it is dependent upon the yearly total capital expense budget 

and the budgeted capital spending for a specific function. Based on Entergy’s experience with 

hours required in similar projects, a 2% of total capital has been assumed to represent the future 

capital suspense of the project. 

 
10

Costs for Wet Scrubbing: 

Costs for Wet Scrubbing were provided in a 2012 estimate from S&L which is provided as 

Attachment C to this submittal. The total equipment cost (EC) was calculated by taking the total 

projected costs (equipment and labor) and subtracting the total construction and erection costs 

from the estimate. These costs are summarized below in Table 3. 
11

TABLE 3: SARGENT & LUNDY 2012 TOTAL EQUIPMENT AND PURCHASED EQUIPMENT COSTS DETAILS, WET 

SCRUBBING

Item

Total Construction & 

Erection Cost

Total Projected Cost 

(Equipment and 

Labor)

Total Equipment 

Costs (EC) (Total 

Projected Cost - Total 

Construction and 

Erection Cost)

1.0 ID FANS 

$ 11,356,500 $ 36,229,400 $ 24,872,900

2.0 NEW STACK 

$ - $ 40,924,000 $ 40,924,000

3.0 LIMESTONE HANDLING SYSTEM 

$ 9,183,200 $ 20,096,900 $ 10,913,700

4.0 REAGENT PREPARATION ISLAND 

$ 14,003,200 $ 35,456,200 $ 21,453,000

5.0 BYPRODUCT DEWATERING ISLAND 

$ 12,824,900 $ 28,730,000 $ 15,905,100

6.0 ABSORBER ISLAND 

$ 101,468,300 $ 254,576,500 $ 153,108,200

7.0 FGD WASTE WATER TREATMENT PLANT 

$ 9,827,600 $ 25,159,500 $ 15,331,900

8.0 COMPRESSED AIR SYSTEM 

$ 709,600 $ 1,700,400 $ 990,800

9.0 SERVICE WATER SYSTEM 

$ 2,468,600 $ 4,932,300 $ 2,463,700

10.0 POTABLE WATER SYSTEM 

$ 301,900 $ 608,400 $ 306,500

11.0 ELECTRICAL (AUX POWER) 

$ 720,500 $ 2,781,300 $ 2,060,800

12.0 FGD DCS SYSTEM 

$ 1,929,900 $ 7,566,500 $ 5,636,600

14.0 RAIL INFRASTRUCTURE 

$ 773,100 $ 1,970,700 $ 1,197,600

15.0 SITE IMPROVEMENTS - CIVIL WORK 

$ 3,591,900 $ 6,906,700 $ 3,314,800

16.0 BOP ITEMS 

$ 1,830,300 $ 3,424,700 $ 1,594,400

17.0 DEMOLITION 

$ 410,400 $ 410,400 $ -

$ 300,074,000

$ 150,037,000

Total Equipment Cost, Unit 1 & Unit 2

Per Unit Total Equipment Cost
12

Cost for the Purchased Equipment Cost (PEC) for wet scrubbing is calculated based on the CCM 

guidance of PEC = 1.18*EC, where EC = $150,037,000, as shown in Table 4. PEC = 1.18* 

$150,037,000 = $177,043,660. 

 

Direct annual costs for wet scrubbing were estimated by S&L in 2011 and are summarized in 

Table 4. 

TABLE 4: SARGENT & LUNDY 2011 DIRECT ANNUAL COSTS FOR WET SCRUBBING

$ 1,513,000

$ 3,378,000

$ 5,067,000

$ 13,639,000

$ 4,038,000

$ 863,000

$ 2,971,000

Total Direct Annual Costs $ 31,469,000

Total Direct Annual Costs, Per Unit $ 15,734,500

Limestone

Waste Ash Disposal

Materials and Supplies

Fixed O&M

Variable O&M

Operating Labor

Maintenance Labor

Aux Power

Total Water Requirement 

NOx BART

x EPA Comment 8 - Although FGR is identified as a technically feasible NOx control option in 

sections 6.1 and 6.2 of the BART report, ADEQ should either justify why this control option is 

subsequently dropped from consideration in the remainder of the BART report, or include it in 

the BART analysis. 

Entergy Response – Based on information provided by S&L in their NOx study report, FGR 

was not anticipated to be a viable NOx control option at White Bluff. The S&L study provides 

the following information regarding FGR. 

NOx reduction efficiency data for coal-fired units with FGR are limited. The amount of 

NOx reduction achievable with FGR depends primarily on the fuel nitrogen content and 

amount of FGR used. Generally, FGR is more effective when used with low nitrogen 

content fuels such as natural gas and propane, since FGR is more effective in controlling 

thermal NOx rather than fuel NOx. Industry experience with FGR on coal-fired units for 

steam temperature control has shown very high maintenance on the gas recirculation fans 

due to erosion and corrosion. Many of the units with FGR for steam temperature control 

have removed the recirculation fans from service. The NOx control achievable on 

tangentially fired units like White Bluff – Units 1&2 with LNB+OFA has been 

comparable to that of FGR at lower capital and O&M cost. Currently, FGR technology is 

not offered by OEMs for coal-fired units. For these reasons, FGR is not a feasible 

technology for the White Bluff coal-fired units. 
13

The June 2013 revised FFA includes a discussion of FGR and a statement that FGR is not a 

feasible technology for White Bluff Units 1 and 2. 

x EPA Comment 9 - In Tables 6-7 and 6-8, Entergy indicates that it evaluated LNB/SOFA to 

achieve 51% control at Unit 1 and 58% control at Unit 2. However, based on the annual NOx

emissions reductions expected to result from LNB/SOFA, it appears that this control scenario 

was evaluated at a removal efficiency of only 42.8% at Unit 1 and 50.4% at Unit 2. Similarly, it 

appears that the removal efficiencies evaluated for the other two NOx control scenarios may be 

lower than what is stated in Tables 6-7 and 6-8. ADEQ should either explain the discrepancy or 

revise Tables 6-7 and 6-8 such that the estimated annual emissions reductions match up with the 

control efficiency for each control scenario. ADEQ should ensure that the most stringent 

emission control level that the technology is capable of achieving has been taken into account 

(70 FR 39166). 

Entergy Response – Entergy believes that the February 2013 FFA evaluates the most stringent 

emission control level that the technology is capable of achieving. As noted above for the SO2

control evaluations, EPA is mixing annual average emission rates during the baseline period with 

proposed 30-day average post-control emission rates. An “apples-to-apples” comparison of the 

maximum 30-day average emission rates during the 2009-2011 baseline period (0.31 lb/MMBtu 

for Unit 1 and 0.36 lb/MMBtu for Unit 2) and the proposed post-control 30-day average 

emission rate of 0.15 lb/MMBtu for each unit results in calculated control efficiencies of 51.6% 

for Unit 1 and 58.3% for Unit 2, consistent with the values provided in Tables 6-7 and 6-8 of the 

FFA. 

x EPA Comment 10 - Please provide a copy of the “2012 S&L NOx Study” referred to in 

footnotes 36-38. The emission rates evaluated for each NOx control scenario and the estimates 

for capital costs, fixed O&M costs, and some of the variable O&M costs for NOx controls were 

based on this study. This documentation should be included in the proposed SIP. 

Entergy Response – S&L has provided an updated study on May 16, 2013. A copy of this 

updated study is included as Appendix E to the June 2013 revised FFA. Please note that the 

variable O&M costs presented in the February 2013 FFA were incorrectly calculated based on an 

annual capacity factor of 100% for each unit. The variable O&M cost estimates contained within 

the revised May 16, 2013 NOx study reflect an annual capacity factor of 76% for each unit, 

which represents a conservative estimate of anticipated actual future annual capacity factors. 

The revised FFA submitted along with this response reflects these corrected estimates of 

anticipated variable O&M costs. 
14

x EPA Comment 11 - As was done in the cost evaluation of SO2 controls, AFUDC costs were 

included in the cost analysis of NOx controls. According to the CCM, AFUDC costs are not 

allowed in estimating capital costs for controls. 

Entergy Response – See Entergy’s response to EPA Comment 7 above regarding AFUDC. 

x EPA Comment 12 - In the cost evaluation of NOx controls Entergy assumed a 20 year 

equipment life for SCR and SNCR. Unless proper documentation is provided to demonstrate that 

the anticipated equipment life of SCR and SNCR is limited to 20 years, we believe that an 

anticipated 30 year equipment life would be more appropriate to use in the cost analysis. If 

Entergy believes that the remaining useful life of the boilers affects the BART determination, 

then an equipment life less than 30 years may be assumed, but this would require a federally 

enforceable restriction preventing further operation of the boilers by a date certain. 

Entergy Response – The assumed equipment life has been revised to 30 years. This change is 

reflected in the costing tables presented in section 6 of the June 2013 revised FFA. Please note 

that the capital recovery period does not affect the outcome of the BART determination in the 

2013 FFA. 

Auxiliary Boiler (SN-05)

x EPA Comment 13 - Please provide modeling files for baseline modeling for SN-05 as well as 

baseline modeling for the three subject-to-BART units combined. 

Entergy Response - The baseline modeling files for SN-05 have been uploaded to same the ftp 

site that contains the modeling files specific to SN-01 and SN-02 (ftp.trinityconsultants.com, 

username = Entergy, password = Trinity). 

There are no baseline modeling files that consider the cumulative impact of SN-01, SN-02, and 

SN-05. Modeling to determine the cumulative impact is not needed as part of making sourcespecific BART determinations. Since the impact of SN-01 and SN-02 by themselves is over 0.5 

ǻdv, it is clear that the cumulative impact of SN-01, SN-02, and SN-05 would also be over 0.5 

ǻdv. 

x EPA Comment 14 - Please explain how baseline maximum 24-hr emissions for SN-05 were 

calculated. We note that the modeled emissions for SO2 of 5.8 lb/hr differ from the baseline 

emission rate modeled in the SIP of 32.5 lb/hr. 

Entergy Response - The maximum short term baseline emission rates for SN-05 were calculated 

using AP-42, Chapter 1, Section 1.3, Tables 1.3-1, 1.3-2, and 1.3-3. The emission factors in 

these tables were multiplied by the maximum heat input rate for SN-05 of 183 MMBtu/hr. With 
15

respect to the SO2, the AP-42 emission factor in lbs/Mgal for No. 2 oil-fired boilers is 142 times 

the weight percent sulfur in the fuel oil. The average percent sulfur in the fuel oil combusted in 

SN-05 for the baseline years 2009-2011 was 0.031% (2009 = 0.043%, 2010 = 0.036%, and 2011 

= 0.013%). This results in an SO2 emission factor of 4.402 lb/Mgal. The factor was converted 

to lb/MMBtu by dividing the factor by the average heat content of the fuel oil from 2009-2011 in 

MMBtu/Mgal. The average heat content of the fuel from 2009-2011 was 138.409 MMBtu/Mgal 

(2009 = 138.708 MMBtu/Mgal, 2010 = 138.404 MMBtu/Mgal, and 2011 = 138.116 

MMBtu/Mgal). The SO2 emissions factor in lb/MMBtu was multiplied by the maximum heat 

rate for the boiler (183 MMBtu/hr) to obtain an emission rate of 5.8 lb/hr. 

x EPA Comment 15 - Are there any limitations to the hours of operation of this unit? What are the 

historical hours of operation of this unit? ADEQ should explain why the baseline is 

representative of this unit’s history, as discussed in 40 CFR Part 51 Appendix Y (section 

IV.D.4.d). 

Entergy Response - Auxiliary boilers are typically utilized to provide steam to a main boiler 

during startup. Thus, the operating hours for auxiliary boilers typically coincide with the startup 

hours for a boiler. Entergy operates SN-05 to provide steam to SN-01 and SN-02 during startup 

when both units are offline, and, in extreme situations, can provide steam to the auxiliary steam 

system. SN-05 is not currently subject to any limit on annual operating hours. Actual annual 

hours of operation for the aux boiler are summarized in the table below for the 2005-2012 

period. Aux. boiler operating hours were not directly tracked by the facility prior to 2005. 

TABLE 5: ACTUAL ANNUAL HOURS OF OPERATION FOR AUX BOILER, 2005-2012

Aux Boiler Operating Hours (hours/year) 

2005 2006 2007 2008 2009 2010 2011 2012 

14 16 89 2.15 63 46 51.5 83.3 

EPA’s BART guidelines stipulate that enforceable limitations on hours of operation or unit 

capacity are only required in situations where projected future values for these parameters differ 

from past practice and this projection has a deciding effect on the BART determination7. 

Entergy projects that future operation of the Aux. boiler will be consistent with past practice thus 

no such restrictions are necessary. 

x EPA Comment 16 - The White Bluff BART analysis states: “Since baseline visibility modeling 

showed that there is no opportunity for visibility improvement attributable to SN-05, because not 

a single day greater than 0.5 ǻdv is associated with SN-05, it is not possible to install control 

equipment to improve visibility. Therefore, no controls is the SO2 BART (NOx BART) 

 

7

 70 FR 39167 
16

determination for SN-05.” This is not an appropriate justification for not completing a BART 

analysis for the unit. The 0.5 dv threshold applies only to the determination of whether the 

facility, considering all BART eligible units, is subject to BART.8 We note that in some cases, 

states may adopt a more streamlined approach to making BART determinations where 

appropriate. For example, a State need not undertake an exhaustive analysis where it is clear that 

controls would be costly and any improvements in visibility resulting from reductions in 

emissions would be negligible. 

Entergy Response - The maximum visibility impairment predicted by the CALPUFF modeling 

system for SN-05 is only 0.036 ǻdv. This is an extremely low level of impairment, so low that it 

is likely falls within the level of accuracy that can be attributed to CALPUFF. In addition, this 

modeling assumes that the auxiliary boiler operates at the maximum daily emission rate 365 days 

per year. Since the existing visibility impairment predicted by CALPUFF is extremely low, to 

the point of practically being nonexistent, the impairment cannot be considered significant such 

as to require controls. Said another way, the impairment is so low that any improvement from 

reductions would be less than negligible. Thus, no controls have been considered for SN-05. 

 

Emission Estimation and modeling

x EPA Comment 17 - To estimate sulfuric acid emissions to model for the baseline and control 

cases, all inorganic PM was assumed to be SO4. This assumption and assumptions of SO4

reductions due to controls impacts the baseline modeling as well as the visibility benefit from 

WFGD when compared to NID. We recommend that sulfuric acid emissions from power plants 

are calculated by estimating the amount of H2SO4 produced and the amount of H2SO4 removed 

by control equipment using information from the Electric Power Research Institute (EPRI) 

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. EPRI, 

Palo Alto, CA: 2010. 1020636, consistent with the methodology detailed in the Technical 

support document that accompanies the Oklahoma FIP. Rather than assuming that 100% of 

inorganic condensable PM is SO4, the EPRI method estimates the amount of SO2 that is oxidized 

to SO3 and then assumes that 100% of SO3 is converted to H2SO4. This methodology also 

accounts for loss of sulfuric acid due to downstream equipment, such as the air pre-heater, ESP 

or FF, and scrubber. 

 

8

 As explained by the preamble of the RHR: ‘‘Failing to consider less-than-perceptible contributions to visibility impairment 

would ignore the CAA’s intent to have BART requirements apply to sources that contribute to, as well as cause, such 

impairment.’’ 70 FR 39104, at 39129. Given that sources are subject to BART based on a contribution threshold of no 

greater than 0.5 deciviews, it would be inconsistent to automatically rule out additional controls where the improvement in 

visibility may be less than 1.0 deciview or even 0.5 deciviews. A perceptible visibility improvement is not a requirement of 

the BART determination because visibility improvements that are not perceptible may still be determined to be significant. 
17

Entergy Response - When using the EPRI methodology, the SO4 baseline emission rates for 

SN-01 and SN-02 are lower than the SO4 emission rates that were included in the February 2013 

FFA based on the use of the NPS speciation profile. For SN-01, the NPS speciation profile gives 

36.77 lb/hr and the EPRI approach gives 5.85 lb/hr. For SN-02, the NPS speciation profile gives 

36.77 lb/hr and the EPRI approach gives 5.90 lb/hr. 

The SO4 rates based on the EPRI approach were calculated as follows: 

SO4 (lb/hr) = SO2 (lb/hr)* K factor (98.07/64.04) * Fuel Impact Factor (Subituminous coal = 

0.0019) * F2 air heater factor (0.36) * F2 ESP Factor (0.72) 

Further, using the EPRI F2 factors which represent the fraction of the baseline SO4 that will 

remain based on the application of specific control devices, it is clear that dry FGD systems 

remove significantly more SO4 than wet FGD systems. The SO4 F2 Factors in Table 4-5 of the 

EPRI guidance are 0.40 for wet FGD and 0.01 for dry FGD. 

Overall, SO4 emissions based on the application of either wet FGD systems or dry FGD systems 

will be lower than baseline. Further, dry FGD systems will remove more SO4 than wet FGD 

systems. Thus, the relationship for the reduction in baseline SO4 based on the use of wet or dry 

FGD from the February 2013 FFA is still relevant. While CALPUFF modeling using SO4 rates 

based on the EPRI approach rather than the NPS speciation profile would be expected to make a 

very slight impact on the level of visibility improvement predicted by CALPUFF for wet and dry 

FGD systems, the modeling would have no impact on the February 2013 FFA’s BART 

determination. 

x EPA Comment 18 - Total PM10 emissions should be estimated based on current PM emissions 

and the anticipated control efficiency or vendor guarantee of the proposed control equipment. 

The appropriate NPS worksheet and coal characteristics should be utilized to determine 

speciation (PMC, PMF, EC and SOA) given the total PM10 emissions (or filterable PM10). We 

note that if White Bluff upgrades the PM controls, the PM emission limit should be adjusted 

accordingly. 

Entergy Response - EPA’s Approval and Promulgation of Implementation Plans, published 

March 12, 20129, determined that the currently installed ESP is BART for PM10 for SN-01 and 

SN-02 with a limit of 0.10 lb/MMBtu. As such, it is not necessary to evaluate further reductions 

to PM10. 

 

9

 77FR 14675 
ATTACHMENT A: SUPPORTING DOCUMENTATION FOR SEMI-DRY SCRUBBING 

COSTS 
TABLE A-1. SARGENT & LUNDY 2009 CONTRACTOR EQUIPMENT, MATERIAL AND LABOR ESTIMATED COSTS 

DETAIL, SEMI-DRY SCRUBBING

Equipment Cost

% of Total 

Equip Cost Material Cost

% of Total 

Material Cost Labor Cost

% of Total 

Labor Cost

UNIT 1 ABSORBER AREA $ 24,000,000 19.6% $ 1,058,000 3.2% $ 13,106,000 9.6%

UNIT 2 ABSORBER AREA $ 24,000,000 19.6% $ 953,000 2.9% $ 13,035,000 9.5%

REAGENT PREP SYSTEM $ 11,965,000 9.8% $ 10,000 0.0% $ 8,694,000 6.4%

WASTE RECYLING SYSTEM $ 4,724,000 3.9% $ - - $ 3,543,000 2.6%

COMMON STRUCTURES AREA $ - $ 2,381,000 7.3% $ 1,949,000 1.4%

REAGENT HANDLING SYSTEM $ - $ 250,000 0.8% $ - -

UNIT 1 FLUE GAS SYSTEM $ 240,000 0.2% $ 11,321,000 34.6% $ 17,107,000 12.5%

UNIT 2 FLUE GAS SYSTEM $ 240,000 0.2% $ 11,321,000 34.6% $ 17,107,000 12.5%

UNIT 1 BOOSTER FANS $ 5,700,000 4.7% $ - - $ 149,000 0.1%

UNIT 2 BOOSTER FANS $ 5,700,000 4.7% $ - - $ 149,000 0.1%

UNIT 1 NEW BAGHOUSE $ 22,000,000 17.9% $ - - $ 8,502,000 6.2%

UNIT 2 NEW BAGHOUSE $ 22,000,000 17.9% $ - - $ 8,502,000 6.2%

INSTRUMENTATION $ 2,008,000 1.6% $ - - $ 190,000 0.1%

MOBILIZE/DEMOBILIZE $ 921,000 0.7%

OVERTIME $ 12,959,000 9.5%

PER DIEM $ 12,823,000 9.4%

FREIGHT $ 1,365,000 4.2%

GENERAL & ADMINISTRATION $ 1,365,000 4.2% $ 5,955,000 4.4%

PROFIT $ 2,729,000 8.3% $ 11,909,000 8.7%

UNIT 2 BOOSTER FANS

UNIT 1 BAGHOUSE 

UNIT 2 BAGHOUSE 

SITE IMPROVEMENTS 

MECHANICAL MISCELLANEOUS 

PIPE RACK

DEMOLITION COSTS

ELECTRICAL 

Total Estimated Costs $ 122,577,000 $ 32,753,000 $ 136,600,000

Total Estimated Costs: Equipment, Material & Labor

Percentage of Total Estimated Cost 42% 11% 47%

Total Estimated Costs, Per Unit $ 61,288,500 $ 16,376,500 $ 68,300,000

Total Cost for Equipment, Materials, and Labor from 2009 S&L Cost Estimate $ 291,930,000

$ 291,930,000

Relationship between Table A-1 to Table 2 – In order to develop the itemized cost shown in 

Table 2 of this response, the cost for each item shown in Table A-1 was multiplied by the ratio of 

the “newer” categorical costs (equipment, material, or labor) to the “older” categorical costs. For 

example, the line item breakout presented in Table 2 for the Unit 1 Absorber Area was derived: 

Submitted Equipment Cost = $24,000,000 * $115,299,965 / $122,577,000 = $22,575,191 

Submitted Material Cost = $1,058,000 * $29,681,855 / $32,753,000 = $958,795 

Submitted Labor Cost = $13,106,000 * $127,215,308 / $127,215,308 = $12,205,592 
Aftachment A-I - Milestone Payment Schedule

White Bluff Unit I&2 DFGD Project

Combined Alstom/ZHI Payment Schedule

Rev. Date - December II, 2009

Description

urchase Order issued by Owner and acknowedged by uoplier

cif’c Process Flow Dagrams and Mass Balances. ssued for

ew

ument

c’ic_General_Arrargerreni_Drawings__ssucd_‘Cr_O.vrer_rev_e ___________ 

c fic P&lDs issued for Owner -ev’e 

F issued for Owner review

Order Issued for booster fans and Lube Oil cooling systems

e of 3D CAD General Arrangement model, issued for Owner

________________

n Selection -Award

rder-issued for FF bags and cages

WF as Bag Supplier -Award Bags

has commenced for ductworkhas commenced for structural steel members

0.87000% $2,161,266

1.34000% $3,328,847

$ (200,000)

$ (300,000)

$ 27,950

$ 41,925

r,Qnnn

WF as Bag Supplier - Released for Fabrication

w model completed and report issued for Owner review 2.38000%

Monthly Invoice

Amount (%)

Monthly Invoice

Amount ($)3

cumulative

Invoiced

Amount (%)2

Cumulative

Invoiced

Amount ($)2

Individual

Milestone Value

(%)

Individual CO#1

Milestone Value

($)

10,930,543

s and motors, issued for Owner review 04500% $ 1,117,896 4.8500% $ 12,048,440 0.22500Y $558,948

Order issued for atomizer assemblies 0.225005’ $558,948

Order issued for lime storage and preparation system — 6.2400% $ 15,501,497 11.0900% $ 27,549,937 3.12000°/ $7,750,749

cific Equipment List, issued for Owner review 3.12000°! $7,750,749

n Selection - Released for Fabrication

Stock Valves -Award —- 

rder issued for SDA shell/casing 0.4500% $ 1,1 17,896 11.5400% $ 28,667,833 0.45000% $1,117,896

e and preparation system, issued for Owner review 0.4500% $ 1,11 7,896 11.9900% $ 29,785,730 0.22500% $558,948

ific Process Control Description, issued for Owner review 0.22500% $558,948

rder issued for Unit 1 SDA inlet duct — 2.2600% $ 5,614,324 14.2500% $ 35,400,054 2.26000 $5,614,324

rder issued for SDA structural support steel 0.4500% $ 1,117,896 14.7000% $ 36,517,951 0.45000 $1,117,896

r fabrication, issued for Owner review 0.4500% $ 1,117,896 15.1500% $ 37,635,847 0.45000 $11 1 7,896

Stock Valves -Released for Fabrication

s Steel Drawings (Released for Fabrication) — 4.0700% $ 10,110,752 1 9.2200% $ 47,746,600 2.03500 / $5,055,376

Access Steel Drawings (Released for Fabrication) 2.03500 $5,055,376

rder issued for 13105 0.4500% $ 1,117,896 19.6700% $ 48,864,496 0.45000 $1,117,896

2.6800% $ 6,657,69

0.5700%

22.3500°,

$ 1.416.002

2.3800%

$ 55,522,190

$

22.9200% S

5,912,43C

1 .3400C

56.938,193

25.3000% S

$3,328,847

er Two Reports submitted (AR Dept of Emergency Management), 0.7000% $ 1,738,950 26.0000% $ 64,589,573 0.70000% $1,738,950

bstruction permit received for cranes >200ft.(FAA), Spill

Control and Countermeasure Plan developed and ready for

ion

ager and Safety Manager are full time presence on-site 2.6700% $ 6,632,852 28.6700% $ 71,222,425 2.67000% $6,632,852

der and cone section for Unit 1 are on site and placed in 2.9900% $ 7,427.801 31.6600% $ 78.650,226 1.49500% $371 3.900

own area —

s set with electncal and plumbing functional. Feb-cation site 1.49500% $371 3.900

ablshed and evei 

,,‘4 ce “ —‘ ‘ v a ‘ e —‘ / ‘° I 3 - ‘

— 

, , 1 71000% S1.28 007

62,850,623

0.57000% Si .416.002

$5,912,430

sructura see: a on se ard pacec r Ire stoage.-aydooo are3

ork sections (50%) are on site

ted, plumb, and bolted

Selection-iJeilvefy ________ Ba So icr Ba Dci e $ 1.13 v’a 474 33.974.743 1.60000% 53.974.743 1.60000% $3,974,743 $ 69,875 $ 1500.000) $ 147.500
Attachment A-I - Milestone Payment Schedule

White Bluff Unit I&2 DFGD Project

Combined AlstomIZHl Payment Schedule

Rev. Date - December II, 2009

ected, olumb. and bolted

work sections (50%) are on site

3.9900% $ 9912015 45.5800% $ 113230490 1.33000%

1 .33000%

$3304005

$3304005

c filter grid steel and structural support steel is on ste and placed

aydown area — 

Description Monthly Invoice Monthly Invoice Cumulative Cumulative Individual Individual CO#1 Amount (%) Amount ($)3 Invoiced Invoiced Milestone Value Milestone Value Amount (%)2 Amount ($)2 (%) ($) 1.33000% $3304005

irder and cone section for Unit 2 are on site and placed in 4.3200% S 10.731.806 49.9000% $ 123,962,296 144000% $3577269

down area

n steel. Alignment complete to extent possible. 1 .44000% $3577,269 

cted, plumb, and bolted. 1 .44000% $3,577,269 

n steel. Alignment complete to extent possible. 4.0800% $ 10,135,595 53.9800% $ 134,097,890 1.36000% $3,378,532 

Roof set in place, plumb, and aligned. I .36000% $3,378,532 

ic Filter plenum walls and hoppers are on site and placed in the 1 .36000% $3,378,532

down area

structural steel is on site and placed in the storage/laydown area 4.0000% $ 9,936,857 57.9800% $ 144,034,747 2.00000% $4,968,429

steel. Alignment complete to extent possible. 2.00000% $4,968,429 

Roof set in place, plumb, and aligned. 3.9900% S 9,912,01 5 61 .9700% S 1 53,946,763 1 .33000% $3,304,005 

steel. Alignment complete to extent possible. 1 .33000% $3,304,005 

r Hoppers and Compartment Walls/Roofs are set. plumb, and 1 .33000% $3,304,005

steel. Alignment complete to extent possible. 3.7000% $ 9,191 .593 65.6700% S 163, 1 38,356 1 .85000% $4,595,797 

steel. Alignment complete to extent possible. 1 .85000% $4,595,797 

Roof set in place, plumb, and aligned. 3.3600% $ 8,346,960 69.0300% $ 171 485,316 0.84000% $2,086,740 

nd Unit 2 DCS equipment on site 0.84000% $2,086,740 

cted, plumb, and bolted. 0.84000% $2,086,740 

cted, plumb, and bolted. 0.84000% $2,086,740 

terfans, motors, and lube oilcooling system equipment installed 3.0300% $ 7,527,169 72.0600% S 179,012,485 1.01000% $2,509,056

cted, plumb, and bolted. 1 .01000% $2,509,056 

r Hoppers and Compartment Walls/Roofs are set. plumb, and 1 .01 000% $2,509,056

cted, plumb, and bolted. 2.9400% $ 7,303,590 75.0000% S 186,316,076 0.98000° $2,434,530 

oof set in place, plumb, and aligned. 0.98000° $2,434,530 

steel. Alignment complete to extent possible. 0. $2,434,530 

cted, plumb, and bolted. 3.0600% $ 7,601,696 78.0600% $ 193,917,771 $3,800,848 

release of O&M manuals, issued for Owner review 1 . $3,800,848 

oof set in place, plumb, and aligned. 3.0000% $ 7,452,643 81 .0600% $ 201 370,414 1 . $2484214

steel, Alignment complete to extent possible. 1 . 0 $2,484,214 

cted, plumb, and bolted, 1. 0 $2,484,214 

steel. Alignment complete to extent possible. 2.8200% S 7,005,484 83.8800% S 208.375,899 1 .410 $3,502,742 

Hoppers and Compartment Walls/Roofs are set. plumb, and 1 .41000% $3,502,742

oof set in place, plumb, and aligned. 2.7600% $ 6,856,432 86.6400% $ 215,232,330 1.38000% $3,428,216 

steel. Alignment complete to extent possible. I .38000% $3,428.21 6 

2.4000% $ 5,962,114 89.0400% $ 221,194,445 0.80000% $1,987,371 

Hoppers and Compartment Walls/Roofs are set, ol.imb. and 0.80000% $1,987,371

ce /S uctu al Con’c e on or lJn/ 38000

2

a ‘— -c c -. -a ce’ -.

compiete. duct reacy to receive flue gas. 2.2300% $ 5.539798 93.5300% 5 232.348.567 2.23000% 55.539.798 

ce of Mechanical Completion for unit 1 0 4500% S 1.117.896 93.9800% S 233.466.464 0.45000% Si .i 1 7.896 

e Test Report issued for Owner review 0.3000% $ 745,264 94.2800% $ 234,211.728 0.30000% $745,264 

ce o Substantial 0 2200% $ 546 527 94 5000% $ 234 758 255 .007400°c = $183 832ce Q00% $ 81 4tt 

$18 i38
Attachment A-i - Milestone Payment Schedule

White Bluff Unit i&2 DFGD Project

Combined AlstomIZHl Payment Schedule

Rev. Date - December 11, 2009

Description Monthly Invoice Monthly Invoice Cumulative Cumulative Individual Individual CO#1

Amount (%> Amount ($)3 Invoiced Invoiced Milestone Value Milestone Value

Amount (%)2 Amount ($)2 (%) ($)

02200% $ 546,527 94.7200% $ 235,304,782 0.22000°! $546,527

g complete, duct ready to receive flue gas, 0.1500% $ 372,632 94.8700% $ 235,677,414 0.15000°! $372,632

ice of Mechanical Completion for Unit 2 0.0700% $ 173.895 94.9400% $ 235.851,309 0.07000°! $173,895

ice of Substantial Completion for Unit 2 0.0600% $ 149,053 950000% $ 236,000,362 0.02000°/ $49,684

rs and construction equipment is removed from site. Fabrication 0.02000°! $49,684

n areas have been returned to pre-mobilized condition.

0.02000% $49,684

ce of Final Acceptance for Unit 1 2.5000% $ 6,210,536 97.5000% $ 242,210,898 2.50000% $6,210,536

ce of Final Acceptance for Unit 2 2.5000% $ 6,210,536 100.0000% S 248,421,434 2.50000% $621 0,536

TOTALS 100.0000% $ 248,421,434 100.00000% $ 248,421,434 (5565,2501

chedule is completed and mutually agreed.

TOTAL ORIGINAL CONTRACT VALUE $ 248,421,434 1 57% Invoiced to date $ 3,900.2 17

TOTAL APPROVED CHANGE ORDER VALUE $ (565,250) 1.51% Payment to date $ 3,751,164

TOTAL CURRENT CONTRACT VALUE $ 247,856,184 0.06% Outstanding Payment $ 149,053

98.43% Outstanding to Invoice $243,955,967
ATTACHMENT B: SUPPORTING DOCUMENTATION FOR SEMI-DRY SCRUBBING 

BOP COSTS 
ACCT..NO. DESCRIPTION

MACOR ACCOUNT

TOTAL TOTAL TOTAL

EQUIPMENT LOST MATERIAL COST LABOR COST

Page: 7’

EstImate No: 23335J7E

TOTAL COST

101 UNIT 1 ABSORBER AREA

101.3 ABSORBER TOWERS

FOUNDATIONS

102 UNIT 2 ABSORBER AREA

102.3 ABSORBER TOWERS

FOUNDATIONS

105 ASH HANDLING SYSTEM

105.1 EQUIPMENT - INCLUDES

FREI GIlT

105.3 2 NEW FGO WASTE SILOS

105.4 2 NEW TRUCK SCALES

105.5 PIPE/TUBE CONVEYOR

TOTAL

COMMON STRUCTURES AREA

I REAGENT PREP ENCLOSURE

50’ x 50’ BA

NEW WAREHOUSE BUILDING,

ZOO’ X 75 X 15’ TALL

NEW ASH HANDLING MAINT

BLDG 45’ x 45’ )C 18

TALL

106

106.1

106 .2

108.!

9;581),000

6;3o,oo 1,164,000

17,00O

1 ,905,0OI

17;723.,O

8W63cIoO

31 ,000

613 ovOo 0

3074?,O0

Sargerit&Ludy WORK PACKAGE

Chicago

W-1O7’3: BALANCE OF PLANT (801’) MATERIAL

Furnish: JUN10 Erection: JUN10 to JUN13

,5043000 ¶‘4O1,O00

boào 1,401,000

2,950,000

los 30;ooo i;i,uoo

8r143.000

1,1990O0

4000

1,r180j001

10,576,000

195,000 492,000 657,00(3

1,062,000 724,000 ,774,U0O

;‘0uO 98,000 241,000

108.8 CIVIL WORK .531,000 730,000 1,261,000

TOTAL 106 4,921,000 2,044;’000 395,OO0:

107 REAGENT HANDLING SYSTEM

107.1 EQUIPMENT INCLUDED WITH P’,512,000 5,610,000 12,622,000

SYSTEM PRICE, INCLUDES

SHIPPING

107.2 4200 TON LIME STOfLASE 2,482,000 5O3B,OO0 7,520,000

SILOS

107.3 ENCLOSED R.ATLCAR 200,000 200,000 400,000

UNLOADING SHED INCL DUST

COLLECTION

107.4 RR TRACKS 856,000 422,000 1,278,000

TOTAL 107 7,012,000 3,538,000 11,270,000 21,820,000
Srgent&Lundy WORK PACKAG3 MAJOR ACCOUNT Page:8

Chicago Estimate No: 23335J7E

N- 1073: BALANCE OF PLANT (BOP) MATERIAL

Furnish: JUN10 Erection: JUN10 to JUN13

TOTAL TOTAL TOTAL

ACCT.NO. DESCRIPTION EQUIPMENT COST MATERIAL COST LABOR COST TOTAL COST

108 UNIT I LOW NOX CONCENTRIC

FIRING (LNCFS) AND

SEPARATED OVERFIRE AIR

REGISTER (SOFA) SYSTEMS

108.1 LNCFS AND SOFA SYSTEM 3,622,000 1,47,00D ;G95,OOB

108.2 MECHANICAL MODIFICATIONS 5OO,OOO -5OO,OOO lO00;OOO

BOP

108.3 CIVIL AND STRUCTURAL 800,000 5b0,000 I,000,QDO

MODIFICATIONS

108.4 ELECTRIC AND I&C 500,000 50O,00 1,000,000

- MODIFICATIONS

108.5 BOILER AND DUCT 100,000 100,000

INSULATION REPAIRS AND

ADDITIONS

TOTAL 108 3622,000 I,600,00til, 3,1173.,00ci 8,295,000

109 UNIT 2 LOW NOX CONCENTRIC

FIRING (LNCFS) AND

SEPARATED OVERF IRE AIR

REGISTER (SOFA) SYSTEMS

109.1 LNCFS AND SOFA SYSTEM 3,622r000 1,473,000 5,095,000

109.2 MECHANICAL MODIFICATIONS 500,000 1,000,000

SOP

109.3 CIVIL AND STRUCTURAL 500,000 500,000 1,000,000

MODIFICATIONS

109.4 ELECTRIC AND 140 500,000 500,000 1,000,000

IFICATIOMS

109.5 BOILER AND DUCT 100,000 100,000 200,000

INSULATION REPAIRS AND

ADDITIONS

TOTAL 109 3,622,000 1,600,000 3,073,000 8,295,000

Ill UNIT I FLUE GAS SYSTEM

1114 WCTWRK ALL SECTIONS 364,000 513,000 877,000

J11.2 PAINT CHIMNEY 100,000 155,000 255,000

TOTAL 111 :464ob 668,000 t,12,000

112 UNIT 2 FLUE GAS SYSTEM

112.1 DUCTWORK ALL SECTIONS 364,000 513,000 877,000
Sargent&Lundy WORK PACKAGE MAJOR ACCOUNT Page:9

Chicago

Eatirsate No; 23335J7E

ACCTND. DESCRIPTION

W-1073: BALANCE OF PLANT (BOP) MATERIAL

L Furnish: JUN10 Erection: JUN10 to JUN13

TOTAL TOTAL

EQUIPMENT COST MATERiAL COST

113

114.

715

I .2

11 3

145.6’

UNIT ‘I BOOSTER FANS

UNIT 2 BOOStER FANS

UNIT 1 BAGHOUSE

CONCRETE FOUNDATIONS

‘IS” AUGER CAST PILE X 60’

LONG

PRE-ENORD BLDG. 8’XlO’

TOTAL 115

TOTAL COST

168,000

•i;i58,0oO

348,000

1O,oOo

1,516,OOO

¶46 UNIT 2 BAGHOIJSE

-i-i

116.2 CONCRETE FOUNDATIONS 1,158,000

‘-k

U83 18” AUGER CAST PILE N 60’ 348,000

LONG

¶164 PRE-EêJGRD BLDG. B’XlO’ Q,OOO

TOTAL 116 1,516,O0

121 CIVIL WORK

121 .1 WATER INTAKE PIJ4P 1O0 , STRUCTURE, 2 BAYS

121.8 1,412,000

121 2,412,000

TOTAL

LAB COST

‘41 ,000

41S4OOO

2,150,Ô00

348,OöO

7,000

2,5O5,O0’

2,150,000

348,000

7,000

2,505,000

1,001 OOO

115,O00

4,116,000

7’90,000

‘j437,O00

,027,000

203,000

4,457,000

151

1511

151.2

151,3

151.4

I 51.5

583,00.,

583,000’

3,308,000

696,000

17,000

4,021 ,OO

3,308,000

696,000

17,000

4,021,000

2,001,000

4,527,000

‘6,528,000

2,910,000

3 ,897 000

2,652,000

794,000

240,000

10,493,000

,O58,OO0

1,303,000

TOTAL

MECHANICAL MISCELLANEOUS

BOP EQUIPMENT

BOP PIPING

SYSTEM PIPING

BOP VALVES

MODEL STUDIES

TOTAL 151

PIPE RACK

C”!lON PIPERACK

ASH CONVEYOR PIPERACK

2,150 LF X 9’ WIDE N 20’

HIGH

2040,0O0 80,0OD

1,625,000

591,000

240, 000

2,040,000 3,996,000

181

181.1

181.2

2,652,000 ‘,4O6,0O0

571,000 732,000
Sergent&Ludy WORK PACKAGE MAJOR ACCOUNT page:1O

Chice9o Estimate No: 23335J7E

W-1073: BALANCE OF PLANT (SOP) MATERIAL

Furnish: JUN10 Erection: JUN10 to JUN13

TOTAL TOTAL TOTAL

ACCT.NO. DESCRIPTION EQUIPMENT COST MATERIAL COST LAB9R COST TOTAL COST

181.3 REAGENT UNLOADING $1,000 1.PBr,000 186,000

PIPERACK 600 LF X 4.5’

WIDE N 20’ HIGH

TOTAL 181 3,304,000 4,243,000 7,547,000

190 DEMOLITION COSTS

190.1 HAZARDOUS MATERIAL 15,000 15,000

ACCUMULATION BUILDING

25’X25’X18’

190.2 PIPE TRENCH AND PIPING 46,000 46,000

N.1784.33 FROM E905’ TO

1180’

190.3 DRAINAGE DITCHS 58,000 58,000

190 4 ASH HANDLING MAINTENANCE 44,000 64 000

BUILDING 45’x45’X18’

190.5 MISC. DEMOLITION COSTS 148,000 148,000

tOTAL 190 311,000

201 ELECTRICAl.

201.1 AUX POWER EQUIPMENT 7,730,000 991,000 4,774,000 16,495,000

201.2 MISC AUX POWER EQUIP 2,705,000 530,000 3,235,000

201.3 CABLE! BUS 2,425,0OO 4,734,000 7,159,000

201 4 RACEWAY 847,000 4,809,000 5,656,000

201.5 SWITCHYARD 995,000 417,000 1,410,000

201.6 STRUCTURES 1,092,000 2,291,000 3,383.000

TOTAL 201 10,435,000 9,348,000 17,555,000 37,3.38,000

211 INSTRLI4ENTATION

211.1 CENS REFURBISHING 356,000 34,000 390,000

211.3 BY INStRUMENTS 455,000 432,000 887,000

211.4 LOCAL HMI 45,000 1,000 46,000

TOTAL 211 856,000 467,000 T323,000

301 MOBIIIZE/DENOSILIZE 81%

OFLA8OR

301.2 MOBILIZE/DEMOBILIZE 8 1 X 710,000

OF LABOR
Sargent&Lw,dy WORK PACKAGE MAJOR ACCOUNT Page:11

Chicago Estimate No: 23335J7E

W-1073; BALANCE OF PLANT (BOP) MATERIAL

Furnish: JUN10 Erection: JUN10 to JUN13

TOTAL TOTAL TOTAL

ACCT.NO. DESCRIPTION EQUIPMENT COST MATERIAL COST LABOR COST TOTAL COST

302 COST DUE TO OVERTIME -

5-10’S

302.2 COST DUE TO OVERTIME f(O,3e3,0O0 i0,363,00O: 5-10’S

304 PER DIEM - B $10 PER

HOUR

304.2 PER DIEM - B $10 PER 10,257,000 10,257,000

HOUR

305 SPARE PARTS B 1% OF

EQUIPMENT

305.2 SPARE PARTS a ix OF 476,000 476,000

EQUIPMENT

306 FREIGHT B 5% OF MATERIAL

306.4 FREIGHT B 5% OF MATERIAL 1,756,000 1,756,000

307 GENERAL 1 ADMINISTRATION

(G&A) B 5% OF MATERIAL

AND LABOR

307.5 GENERAL B ADMINISTRATION 1,756,000 3,i43,OO9 4,899,000

(G&A) a 5Z OF MATERIAL

AND LABOR

307.6 GENERAL & ADMINISTRAtION 1,456,000 1,456,000

(G&A) a 5% OF MATERIAL

AND LABOR

tOTAL 307 1,756,000 4,599,000 6,355,000

308 PROFIT Bi0% OF MATERIAL

ANDLABOR

308 5 PROFIT BlOX OF MATERIAL 3,512,000 6,285,000 9,797,000

AND LABOR

308.6 PROFIT BlOX OF MATERIAL 2,913,000 2,913,000

ANt) LABOR

TOTAL 308 3,512,000 9,198,000 12,710,000

360 NON CONTRACTOR INDIRECTS

360.8 ENGINEERING . 9,855,000 9,855,000 -

TOTAL W-1073 46,037,000 42,144,000 115,990,000 204,171,000
ATTACHMENT C: SUPPORTING DOCUMENTATION FOR WET SCRUBBING COSTS 
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE SUMMARY

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

1.0 ID FANS $ 18,880,700 $ 5,992,200 $ 

2.0 NEW STACK $ - $ - $ 

3.0 LIMESTONE HANDLING SYSTEM $ 7,183,300 $ 3,730,400 $ 

4.0 REAGENT PREPARATION ISLAND $ 15,457,600 $ 5,995,400 $ 

5.0 BYPRODUCT DEWATERING ISLAND $ 9,783,900 $ 6,121,200 $ 

6.0 ABSORBER ISLAND $ 95,571,200 $ 57,537,000 $ 

7.0 FGD WASTE WATER TREATMENT PLANT $ 5,406,000 $ 9,925,900 $ 

8.0 COMPRESSED AIR SYSTEM $ 790,600 $ 200,200 $ 

9.0 SERVICE WATER SYSTEM $ 977,600 $ 1,486,100 $ 

10.0 POTABLE WATER SYSTEM $ 172,000 $ 134,500 $ 

11.0 ELECTRICAL (AUX POWER) $ 1,868,100 $ 192,700 $ 

12.0 FGD DCS SYSTEM $ 1,030,000 $ 4,606,600 $ 

13.0 ACI SYSTEM $ - $ - $ 

14.0 RAIL INFRASTRUCTURE $ 226,600 $ 971,000 $ 

15.0 SITE IMPROVEMENTS - CIVIL WORK $ 416,600 $ 2,898,200 $ 

16.0 BOP ITEMS $ 216,300 $ 1,378,100 $ 

17.0 DEMOLITION $ - $ - $ 

Sargent & Lundy, LLC

Page 1 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE SUMMARY

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

99.0 OVERALL - EQUIPMENT, MATERIAL AND LABOR COSTS - 

PROJECT TOTAL

 $ 157,980,500 $ 101,169,500 $ 

OVERALL - OTHER DIRECT & CONSTRUCTION INDIRECT COSTS - PROJECT TOTAL

 $ 8,826,000 $ 25,798,200 $ 

OVERALL TOTAL DIRECT & CONSTRUCTION INDIRECT COST - PROJECT TOTAL

 $ 166,806,500 $ 126,967,700 $ 

OVERALL PROJECT INDIRECT COSTS

ENGINEERING, PROCUREMENT, & PROJECT SERVICES 

CONSTRUCTION MANAGEMENT S-U / COMMISSIONING OWNER'S COST 

SUBTOTAL - INDIRECT COSTS TOTAL PROJECT DIRECT AND INDIRECT COSTS ESCALATION 

EQUIPMENT MATERIAL LABOR INDIRECTS 

CONTINGENCY TOTAL PROJECT COST 

Page 2 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

1.0 ID FANS $ 18,880,700 $ 5,992,200 $ 

1.1 ID FANS - OEM EQUIPMENT 2,070,000 ACFM WITH 21,500 HP 

MOTORS ($825,000 EACH. INCLUDES HYDRAULIC OIL UNITS, SEAL AIR FAN SKIDS, VIBRATION MONITORING EQUIPMENT, FAN STALL EQUIPMENT,

FIELD SERVICE REP FOR 140 DAYS

 $ 15,540,000 $ - $ 

1.2 PIPING & SUPPORTS - MECHANICAL $ 59,700 $ 42,700 $ 1.3 DAMPERS $ 925,400 $ - $ 1.4 EXPANSION JOINTS $ - $ 165,600 $ 1.5 DUCTWORK INCLUDES INTERNAL BRACING AND 

TURNING VANES

 $ - $ 2,301,000 $ 

1.6 DUCT SUPPORT STEEL THREE-COAT SHOP PAINT $ - $ 1,026,600 $ 1.7 ID FAN INSULATION & LAGGING TOTAL FOR TWO FANS. PRICE 

REFLECTS STANDARD ACOUSTICAL INSULATION

 $ - $ 400,000 $ 

1.8 DUCTWORK INSULATION & LAGGING 0.0 $ - $ 578,200 $ 1.9 SUPPORT STEEL - FOUNDATIONS 0.0 $ - $ 147,300 $ 1.10 ID FAN PDC / CONTROL ROOM - FOUNDATIONS 0.00 $ - $ 244,100 $ 1.11 ID FAN PDC / CONTROL ROOM - CONCRETE PIERS 28 PIERS $ - $ 41,400 $ 1.12 ID FAN - FOUNDATIONS TOTAL FOR TWO FANS $ - $ 458,600 $ 1.13 SWITCHGEAR 0.00 $ 742,600 $ - $ 1.14 MCC 0.00 $ 129,300 $ - $ 1.15 ID FAN PDC / CONTROL ROOM 25W X 70' X 13'H $ 901,300 $ - $ 1.16 138 kV PANELS - RELAY 0.00 $ 103,000 $ - $ 1.17 2000A, 15KV CABLE BUS & TERMINATIONS 0.00 $ 136,600 $ 7,200 $ 1.18 MIMIC PANELS 0.00 $ 18,000 $ - $ 1.19 EMERGENCY POWER SYSTEM 0.00 $ 294,100 $ - $ 1.20 GROUNDING 0.00 $ 3,900 $ - $ 1.21 LIGHTING/ TRANSFORMERS & PANELS $ 26,800 $ 30,000 $ 1.22 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 390,600 $ 1.23 HIGH VOLTAGE POWER CABLE & TERMINATION 1/C # 500KCMIL-15KV $ - $ 12,500 $ 1.24 LOW VOLTAGE POWER CABLE & TERMINATION 0.00 $ - $ - $ 1.25 CONTROL & INSTRUMENT CABLE #14, #16 & PR # 20 & SHLD WIRE $ - $ 41,000 $ 1.26 DUCT BANK 37"H X 62.5"W (75'+150'=225') $ - $ 73,400 $ 1.27 COMMUNICATIONS $ - $ 17,000 $ Sargent & Lundy, LLC

Page 3 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

1.28 LIGHTNING PROTECTION $ - $ 7,000 $ 

1.29 SECURITY SYSTEM $ - $ 8,000 $ 

2.0 NEW STACK $ - $ - $ 

2.1 CONCRETE STACK (WET - FRP LINED) 0.0 $ - $ - $ 

3.0 LIMESTONE HANDLING SYSTEM $ 7,183,300 $ 3,730,400 $ 

3.1 MATERIAL HANDLING EQUIPMENT $ 4,908,200 $ 845,000 $ 

3.2 FIRE PROTECTION SYSTEM FOR BELT CONVEYORS DELUGE SYSTEM, DRY PIPE, 

SENSORS, ACTIVATION VALVE AND FM APPROVED PANEL - SUBCONTRACT PRICE FOR ALL CONVEYORS INCLUDES LABOR

 $ 679,800 $ - $ 

3.3 PIPING - MECHANICAL $ 4,900 $ 1,700 $ 

3.4 CONVEYOR STRUCTURE SUPPORT STEEL THREE-COAT SHOP PAINT $ - $ 290,000 $ 3.5 CONVEYOR SUPPORT STEEL - FOUNDATIONS $ - $ 16,000 $ 

3.6 RAILCAR LIMESTONE UNLOADING HOPPER, CONVEYOR TUNNEL 

AND ESCAPE TUNNEL - FOUNDATIONS

 $ - $ 542,000 $ 

3.7 LIMESTONE TRANSFER TOWER - FOUNDATIONS $ - $ 15,400 $ 

3.8 LIMESTONE TRANSFER CONVEYOR - FOUNDATIONS $ - $ 62,000 $ 

3.9 LIMESTONE RECLAIM HOPPER, CONVEYOR TUNNEL AND 

ESCAPE TUNNEL - FOUNDATIONS

 $ - $ 542,000 $ 

3.10 LIMESTONE UNLOADING PDC - FOUNDATIONS $ - $ 24,500 $ 

3.11 LIMESTONE UNLOADING PDC - CONCRETE PIERS 10 PIERS $ - $ 6,900 $ 3.12 LIMESTONE RECLAIM PDC - FOUNDATIONS $ - $ 16,800 $ 

3.13 LIMESTONE RECLAIM PDC - CONCRETE PIERS 10 PIERS $ - $ 6,900 $ 

3.14 TRANSFORMERS LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 175,100 $ - $ 

Page 4 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

3.15 SWITCHGEAR LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 161,500 $ - $ 

3.16 LIMESTONE UNLOADING PDC 18W X 50' X 10'H $ 463,500 $ - $ 

3.17 LIMESTONE RECLAIM PDC 15W X 30' X 10'H $ 231,800 $ - $ 

3.18 MCC LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 127,400 $ - $ 

3.19 CABLE BUS DUCT LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 138,700 $ 5,400 $ 

3.20 MIMIC PANELS $ 18,000 $ - $ 

3.21 EMERGENCY POWER SYSTEM LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 222,800 $ - $ 

3.22 LIGHTING/ TRANSFORMERS & PANELS $ 26,800 $ 67,500 $ 

3.23 GROUNDING LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ 24,800 $ - $ 

3.24 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 801,100 $ 

3.25 HIGH VOLTAGE POWER CABLE & TERMINATION 1/C # 500KCMIL-15KV $ - $ 33,400 $ 

3.26 LOW VOLTAGE POWER CABLE & TERMINATION 0.00 $ - $ 130,600 $ 

Page 5 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

3.27 CONTROL & INSTRUMENT CABLE #14, #16 & PR # 20 & SHLD WIRE $ - $ 140,800 $ 3.28 DUCT BANK DUCT BANK WITH 12-5" CONDUIT, 

37"H X 62.5"W (325'+50'=375')

 $ - $ 122,400 $ 

3.29 FOUNDATIONS FOR TRANSFORMERS LIMESTONE UNLOADING & RECLAIM 

AREAS

 $ - $ 3,500 $ 

3.30 COMMUNICATIONS $ - $ 34,000 $ 

3.31 LIGHTNING PROTECTION $ - $ 6,500 $ 

3.32 SECURITY SYSTEM $ - $ 16,000 $ 

4.0 REAGENT PREPARATION ISLAND $ 15,457,600 $ 5,995,400 $ 

4.1 MECHANICAL EQUIPMENT INCLUDES LIMESTONE FEEDERS, 

FROM THE SILOS THROUGH THE SLURRY STORAGE TANKS AND TRANSFER PUMPS WITH INTEGRAL PIPING

 $ 14,709,700 $ - $ 

4.2 REAGENT PREPARATION BUILDING SUMP PUMPS DUPLEX. INCLUDES CHECK & 

ISOLATION VALVES

 $ 28,800 $ - $ 

4.3 AGITATOR FOR SUMP PUMPS 5 HP $ 12,400 $ - $ 4.4 PIPING - MECHANICAL $ 373,500 $ 279,600 $ 

4.5 LIMESTONE SLURRY TANKS - FOUNDATIONS $ - $ 166,400 $ 

4.6 REAGENT PREPARATION BUILDING - FOUNDATIONS $ - $ 649,100 $ 

4.7 REAGENT PREPARATION BUILDING 120' L X 125' W X 130' H $ 277,500 $ 4,686,500 $ 4.8 PIPE SUPPORT PAD - REAGENT PREP BUILDING $ - $ 13,800 $ 

4.9 LIGHTING/ TRANSFORMERS & PANELS $ 53,600 $ 135,000 $ 

4.10 GROUNDING $ 2,100 $ - $ 

4.11 RACEWAY, CABLE TRAY, & CONDUIT INCLUDED IN ABSORBER ISLAND, 

SECTION 7.0

 $ - $ - $ 

4.12 COMMUNICATIONS $ - $ 34,000 $ 

4.13 LIGHTNING PROTECTION $ - $ 23,000 $ 

4.14 SECURITY SYSTEM $ - $ 8,000 $ 

Page 6 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

5.0 BYPRODUCT DEWATERING ISLAND $ 9,783,900 $ 6,121,200 $ 

5.1 MECHANICAL EQUIPMENT PRIMARY & SECONDARY $ 7,323,300 $ - $ 5.2 PIPING - MECHANICAL $ 378,500 $ 1,626,500 $ 

5.3 MATERIAL HANDLING EQUIPMENT $ 745,900 $ 5,000 $ 

5.4 FIRE PROTECTION SYSTEM FOR BELT CONVEYORS DELUGE SYSTEM, DRY PIPE, 

SENSORS, ACTIVATION VALVE AND 

FM APPROVED PANEL 

 $ 175,100 $ - $ 

5.5 BYPRODUCT DEWATERING BUILDING SUMP PUMPS & 

AGITATORS

 $ 41,200 $ - $ 

5.6 CONVEYOR STRUCTURE SUPPORT STEEL THREE-COAT SHOP PAINT $ - $ 99,000 $ 

5.7 BYPRODUCT STACKOUT CONVEYOR - FOUNDATIONS $ - $ 30,100 $ 

5.8 BYPRODUCT STACKOUT PILE - FOUNDATIONS INCLUDES CONTAINMENT AREA $ - $ 1,155,700 $ 

5.9 BYPRODUCT CONTAINMENT WALLS $ - $ 137,300 $ 

5.10 INSTALL WIND SCREEN $ - $ 525,000 $ 

5.11 BYPRODUCT DEWATERING BUILDING - FOUNDATIONS $ - $ 275,400 $ 

5.12 BYPRODUCT DEWATERING BUILDING 120' L X 71' W X 65' H $ 149,600 $ 1,536,800 $ 

5.13 PIPE SUPPORT PAD $ - $ 13,800 $ 

5.14 TRANSFORMERS $ 175,100 $ - $ 

5.15 SWITCHGEAR 480V LOW VOLATAGE SWITCHGEAR, $ 201,900 $ - $ 5.16 CABLE BUS DUCT $ 277,500 $ 10,800 $ 

5.17 MCC $ 127,300 $ - $ 

5.18 MIMIC PANELS $ 18,000 $ - $ 

5.19 EMERGENCY POWER SYSTEM $ 111,300 $ - $ 

5.20 GROUNDING $ 5,600 $ - $ 

5.21 LIGHTING/ TRANSFORMERS & PANELS $ 53,600 $ 135,000 $ 

5.22 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 326,100 $ 

5.23 HIGH VOLTAGE POWER CABLE & TERMINATION 1/C # 500KCMIL-15KV $ - $ 13,900 $ 5.24 LOW VOLTAGE POWER CABLE & TERMINATION 0.00 $ - $ 73,100 $ 

5.25 CONTROL & INSTRUMENT CABLE #14, #16 & PR # 20 & SHLD WIRE $ - $ 99,200 $ 5.26 FOUNDATIONS FOR TRANSFORMERS $ - $ 3,500 $ 

5.27 COMMUNICATIONS $ - $ 34,000 $ 

5.28 LIGHTNING PROTECTION $ - $ 13,000 $ 

Page 7 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

5.29 SECURITY SYSTEM $ - $ 8,000 $ 

6.0 ABSORBER ISLAND $ 95,571,200 $ 57,537,000 $ 

6.1 MECHANICAL EQUIPMENT INCLUDES ABSORBER MODULE $ 83,613,300 $ - $ 6.2 ADDITIONAL COST FOR C276 ABSORBER SHELL MATERIAL 

ABOVE THE PRICE OF A2205 ABSORBER SHELL

INCLUDES MATERIAL AND WELDING ROD COST DIFFERENTIAL49,800 TOTAL SF

 $ - $ 30,676,800 $ 

6.3 ABSORBER BUILDING SUMP PUMPS DUPLEX. INCLUDES CHECK & $ 57,700 $ - $ 6.4 AGITATOR FOR SUMP PUMPS 5 HP $ 24,700 $ - $ 6.5 EMERGENCY DIESEL DRIVEN QUENCH PUMP WITH FUEL DAY TANK. 

FOUNDATIONS INCLUDED WITH 

 $ 309,000 $ - $ 

6.6 PIPING - MECHANICAL ALL PIPING INCLUDED IN OEM $ - $ - $ 6.7 ABSORBER VESSEL - FOUNDATIONS $ - $ 733,900 $ 

6.8 ABSORBER BUILDING - FOUNDATIONS $ - $ 1,088,600 $ 

6.9 ABSORBER BUILDING 150' L X 85' W X 60' H $ 338,900 $ 4,971,200 $ 

6.10 PIPE SUPPORT PAD - ABSORBER BUILDING $ - $ 15,400 $ 

6.11 OXIDATION AIR BLOWER BUILDING - FOUNDATIONS $ - $ 73,800 $ 

6.12 OXIDATION AIR BLOWER BUILDING 30' L X 30' W X 25' H $ 69,600 $ 347,700 $ 6.13 PIPE SUPPORT PAD - OXIDATION BUILDING $ - $ 15,400 $ 

6.14 DUCTWORK INCLUDES INTERNAL BRACING AND $ - $ 7,117,500 $ 6.15 DUCT SUPPORT STEEL THREE-COAT SHOP PAINT $ - $ 3,172,600 $ 6.16 DUCTWORK INSULATION & LAGGING $ - $ 2,522,400 $ 

6.17 FOUNDATIONS FOR DUCT SUPPORT STEEL $ - $ 137,800 $ 

6.18 TRANSFORMERS $ 2,432,900 $ - $ 

6.19 SWITCHGEAR $ 3,787,100 $ - $ 

6.20 CABLE BUS & TERMINATIONS $ 3,416,100 $ 93,100 $ 

6.21 MCC $ 891,200 $ - $ 

6.22 MIMIC PANELS $ 36,100 $ - $ 

6.23 GROUNDING $ 32,900 $ - $ 

6.24 LIGHTING/ TRANSFORMERS & PANELS $ 338,900 $ 330,000 $ 

6.25 EMERGENCY POWER SYSTEM $ 222,800 $ - $ 

6.26 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 3,031,300 $ 

6.27 HIGH VOLTAGE POWER CABLE & TERMINATION $ - $ 116,800 $ 

Page 8 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

6.28 MEDIUM VOLTAGE POWER CABLE & TERMINATION $ - $ 229,100 $ 

6.29 LOW VOLTAGE POWER CABLE & TERMINATION $ - $ 1,591,700 $ 

6.30 CONTROL & INSTRUMENT CABLE $ - $ 1,024,000 $ 

6.31 FOUNDATION FOR TRANSFORMERS $ - $ 118,000 $ 

6.32 TRANSFORMER FIRE WALLS $ - $ 6,900 $ 

6.33 COMMUNICATIONS $ - $ 68,000 $ 

6.34 LIGHTNING PROTECTION $ - $ 39,000 $ 

6.35 SECURITY SYSTEM $ - $ 16,000 $ 

7.0 FGD WASTE WATER TREATMENT PLANT $ 5,406,000 $ 9,925,900 $ 

7.1 WWT MECHANICAL EQUIPMENT: $ 4,635,000 $ - $ 

7.2 PIPING - MECHANICAL $ 96,400 $ 562,300 $ 

7.3 PUMPS $ 119,500 $ 58,500 $ 

7.4 TANKS $ - $ 4,770,000 $ 

7.5 PRIMARY CLARIFIER - FOUNDATIONS $ - $ 46,900 $ 

7.6 SECONDARY CLARIFIER - FOUNDATIONS $ - $ 46,900 $ 

7.7 RECLAIM WATER TANKS - FOUNDATIONS TOTAL FOR TWO TANKS $ - $ 51,900 $ 7.8 EQUALIZATION TANKS - FOUNDATIONS TOTAL FOR TWO TANKS $ - $ 10,900 $ 7.9 MAINTENANCE STORAGE TANK - FOUNDATIONS $ - $ 199,900 $ 

7.10 WWT BUILDING - FOUNDATIONS $ - $ 603,900 $ 

7.11 WWT BUILDING 125' L X 90' W X 25' H $ 86,500 $ 1,737,800 $ 7.12 PIPE SUPPORT PAD $ - $ 27,600 $ 

7.13 MCC $ 127,300 $ - $ 

7.14 EMERGENCY POWER SYSTEM $ 222,800 $ - $ 

7.15 GROUNDING $ 11,400 $ - $ 

7.16 LIGHTING / TRANSFORMERS & PANELS $ 107,100 $ 120,000 $ 

7.17 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 1,072,500 $ 

7.18 LOW VOLTAGE POWER CABLE & TERMINATION $ - $ 500,800 $ 

7.19 CONTROL & INSTRUMENT CABLE #14, #16 & PR # 20 & SHLD WIRE $ - $ 204,800 $ 7.20 COMMUNICATIONS $ - $ 68,000 $ 

7.21 LIGHTNING PROTECTION $ - $ 32,000 $ 

7.22 SECURITY SYSTEM $ - $ 16,000 $ 

8.0 COMPRESSED AIR SYSTEM $ 790,600 $ 200,200 $ 

Page 9 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

8.1 AIR COMPRESSOR & AUXILIARIES 3000 CFM $ 411,000 $ - $ 

8.2 PIPING - MECHANICAL $ 379,600 $ 200,200 $ 

8.3 ELECTRICAL INCLUDED IN REAGENT PREPARATION, SECTION 5.0 $ - $ - $ 9.0 SERVICE WATER SYSTEM $ 977,600 $ 1,486,100 $ 

9.1 PUMPS INCLUDES SELF-CLEANING 

STRAINERS

 $ 210,100 $ - $ 

9.2 PIPING - MECHANICAL $ 493,200 $ 1,205,400 $ 

9.3 PIPING - FIRE PROTECTION SYSTEM $ 274,300 $ 143,400 $ 

9.4 TANKS $ - $ 120,000 $ 

9.5 SERVICE WATER TANK & PUMP - FOUNDATIONS $ - $ 17,300 $ 

9.6 ELECTRICAL INCLUDED IN REAGENT 

PREPARATION, SECTION 5.0

 $ - $ - $ 

10.0 POTABLE WATER SYSTEM $ 172,000 $ 134,500 $ 

10.1 PUMPS $ 30,900 $ - $ 

10.2 PIPING - MECHANICAL $ 141,100 $ 120,800 $ 

10.3 TANKS $ - $ 8,500 $ 

10.4 POTABLE WATER TANK & PUMP - FOUNDATIONS $ - $ 5,200 $ 

10.5 ELECTRICAL INCLUDED IN REAGENT 

PREPARATION, SECTION 5.0

 $ - $ - $ 

11.0 ELECTRICAL (AUX POWER) $ 1,868,100 $ 192,700 $ 

11.1 138/13.8 KV STATION SERVICE TRANSFORMERS $ 1,432,200 $ - $ 

11.2 138KV MAIN FEEDER & TERMINATIONS $ 271,800 $ - $ 

11.3 SWITCHGEAR $ 127,900 $ - $ 

11.4 DUCTBANKS $ - $ 108,200 $ 

11.5 GROUNDING $ 10,400 $ - $ 

11.6 OUTDOOR LIGHTING $ 25,800 $ - $ 

11.7 FOUNDATION FOR AUX TRANSFORMER $ - $ 63,200 $ 

11.8 FIRE WALL FOR AUX TRANSFORMER $ - $ 21,300 $ 

12.0 FGD DCS SYSTEM $ 1,030,000 $ 4,606,600 $ 

12.1 DCS 5000 I/O POINTS $ - $ 3,750,000 $ 

12.2 DCS - VENDOR FIELD SUPPORT 200 MANDAYS @ $1500/DAY - SHOWN $ 309,000 $ - $ 

Page 10 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

12.3 LOCALLY MOUNTED INSTRUMENTS $ - $ 856,600 $ 

13.0 ACI SYSTEM $ - $ - $ 

13.1 CONCRETE $ - $ - $ 

13.2 STEEL $ - $ - $ 

13.3 ARCHITECTURAL $ - $ 

13.4 MECHANICAL EQUIPMENT $ - $ 

13.5 PIPING $ - $ 

13.6 ELECTRICAL EQUIPMENT $ - $ 

13.7 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 

13.8 CABLE $ - $ - $ 

14.0 RAIL INFRASTRUCTURE $ 226,600 $ 971,000 $ 

14.1 ENCLOSED RAILCAR UNLOADING SHED INCL DUST COLLECTION 0.0 $ - $ 220,000 $ 

14.2 NEW TRACKS 0.0 $ - $ 621,000 $ 

14.3 REALIGN AND RESURFACE TRACKS 0.0 $ - $ 130,000 $ 

14.4 TRACKMOBILE 0.0 $ 226,600 $ - $ 

15.0 SITE IMPROVEMENTS - CIVIL WORK $ 416,600 $ 2,898,200 $ 

15.1 SITE GRADING $ - $ - $ 

15.2 ROADS & SURFACING $ - $ 605,100 $ 

15.3 LIMESTONE HANDLING & STORAGE $ - $ 340,100 $ 

15.4 GYPSUM HANDLING & STORAGE $ - $ 1,147,200 $ 

15.5 GYPSUM RUNOFF POND $ 61,800 $ 110,400 $ 

15.6 BYPRODUCT POND PUMP STRUCTURE - CONCRETE $ - $ 47,000 $ 

15.7 STORMWATER DRAINAGE TRENCH 2' W X 3' DEEP CAST-IN-PLACE $ - $ 472,500 $ 

15.8 STORMWATER RUNOFF POND $ - $ 15,000 $ 

15.9 STORM WATER POND PUMP STRUCTURE - CONCRETE $ 92,700 $ 42,300 $ 

15.10 OILY WATER SEWER $ 4,600 $ 80,600 $ 15.11 OIL SEPARATOR 500 GPM W/ INTEGRAL LIFT STATION $ 103,000 $ - $ 15.12 SANITARY SEWER $ - $ 22,200 $ 15.13 SANITARY LIFT STATION PACKAGED TYPE COMPLETE WITH $ 154,500 $ - $ 15.14 EROSION & SEDIMENT CONTROL $ - $ 15,800 $ 

Page 11 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

16.0 BOP ITEMS $ 216,300 $ 1,378,100 $ 

16.1 PIPE INSULATION AVERAGE 6" PIPE SIZE $ - $ 78,000 $ 16.2 HEAT TRACING $ - $ 332,700 $ 

16.3 TOUCH UP PAINT (INCLUDES PAINTING CS PIPE) $ - $ 181,900 $ 

16.4 HOISTS & TROLLEYS $ 185,400 $ 210,000 $ 

16.5 MISC AUX STEEL FOR PIPE SUPPORTS FIELD FABRICATED $ - $ 140,000 $ 16.6 MISC PIPE SUPPORT FOUNDATIONS $ - $ 10,500 $ 

16.7 EYE WASH STATIONS $ 30,900 $ 5,000 $ 

16.8 FIRE PROTECTION FOR MISC BUILDINGS & AREAS $ - $ 420,000 $ 

17.0 DEMOLITION $ - $ - $ 

17.1 MISCELLANEOUS DEMOLISHING COSTS $ - $ - $ 

99.0 OVERALL - EQUIPMENT, MATERIAL AND LABOR COSTS - 

PROJECT TOTAL

 $ 157,980,500 $ 101,169,500 $ 

OVERALL - OTHER DIRECT & CONSTRUCTION INDIRECT COSTS - PROJECT TOTAL

 $ 8,826,000 $ 25,798,200 $ 

OVERALL TOTAL DIRECT & CONSTRUCTION INDIRECT COST - PROJECT TOTAL

 $ 166,806,500 $ 126,967,700 $ 

OVERALL PROJECT INDIRECT COSTS

ENGINEERING, PROCUREMENT, & PROJECT SERVICES 

CONSTRUCTION MANAGEMENT S-U / COMMISSIONING OWNER'S COST 

SUBTOTAL - INDIRECT COSTS TOTAL PROJECT DIRECT AND INDIRECT COSTS ESCALATION 

EQUIPMENT 

Page 12 of 13
ENTERGY 

WHITE BLUFF STATION UNIT 1 & 2 

WET FGD - 2.0 LB/MMBTU 

ORDER OF MAGNITUDE COST 

ESTIMATE

Account No. Item Description Scope Definition Total Equipment Cost Total Material Cost 

Sargent & Lundy, LLC

MATERIAL LABOR INDIRECTS 

CONTINGENCY TOTAL PROJECT COST 

Page 13 of 13
ATTACHMENT D: 2008 S&L WET VS. DRY FGD STUDY 
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

SL-009510

Rev. 3

October 28, 2008

Project 12303-004

Prepared by

55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000 
LEGAL NOTICE 

This report was prepared by Sargent & Lundy, L.L.C., hereinafter referred to as S&L, expressly for Entergy Arkansas, Inc., 

hereinafter referred to as Entergy. Neither S&L nor any person acting on its behalf (a) makes any warranty, express or implied,

with respect to the use of any information or methods disclosed in this report or (b) assumes any liability with respect to the

use of any information or methods disclosed in this report. 
WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

CONTRIBUTORS 

PREPARED BY: 

 W. A Patel K. S Aita 

 Processes Processes 

REVIEWED BY: 

 S. M. Katzberger 

 Processes 

APPROVED BY: 

 C. A. Radek Date 

 Project Manager 
i

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

CONTENTS 

Section Page

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

1. INTRODUCTION ...................................................................................................................................1-1

1.1 PURPOSE........................................................................................................................................................ 1-1

1.2 STUDY APPROACH......................................................................................................................................... 1-1

1.3 STUDY BASIS................................................................................................................................................. 1-2

1.3.1 Unit Design ........................................................................................................................................... 1-2

1.3.2 Economic Information........................................................................................................................... 1-3

1.3.3 Fuel Information.................................................................................................................................... 1-4

2. SULFUR REDUCTION TECHNOLOGY EVALUATIONS ..........................................................................2-1

2.1 PURPOSE........................................................................................................................................................ 2-1

2.2 TECHNOLOGY DESCRIPTIONS........................................................................................................................ 2-1

2.2.1 Lime Spray Dry FGD (LSD FGD)........................................................................................................ 2-2

2.2.2 Wet Limestone FGD with Forced Oxidation (LSFO FGD)................................................................ 2-11

3. COMPARISON OF LSD AND LSFO FGD PROCESSES.........................................................................3-1

3.1 DESIGN BASIS................................................................................................................................................ 3-1

3.2 GENERAL ARRANGEMENT............................................................................................................................. 3-3

3.2.1 Lime Spray Dryer (LSD) FGD.............................................................................................................. 3-3

3.2.2 Wet FGD ............................................................................................................................................... 3-3

3.3 COMPARISON OF SYSTEM FEATURES ............................................................................................................ 3-4

3.3.1 Absorber Vessel .................................................................................................................................... 3-4

3.3.2 Chimney ................................................................................................................................................ 3-5

3.3.3 Chemistry .............................................................................................................................................. 3-5

3.3.4 Chloride Blowdown .............................................................................................................................. 3-6

3.3.5 Water Consumption............................................................................................................................... 3-6

3.3.6 SO2 Control ........................................................................................................................................... 3-6

3.3.7 Particulate Control ................................................................................................................................ 3-7

3.3.8 SO3 Removal......................................................................................................................................... 3-8
ii

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

CONTENTS 

Section Page

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.3.9 Mercury Collection ............................................................................................................................... 3-8

3.3.10 Preliminary CO2 Considerations for Dry and Wet FGD....................................................................... 3-9

3.4 COMPARISON OF CONSUMABLES AND WASTES.......................................................................................... 3-10

3.4.1 Power Consumption ............................................................................................................................ 3-10

3.4.2 Reagent Consumption ......................................................................................................................... 3-11

3.4.3 Waste Byproducts ............................................................................................................................... 3-11

3.5 SULFUR REDUCTION TECHNOLOGY COST EVALUATION ............................................................................ 3-12

3.5.1 Capital Cost......................................................................................................................................... 3-12

3.5.2 Fixed and Variable Operating Costs ................................................................................................... 3-15

3.5.3 Preliminary Cost Summary ................................................................................................................. 3-17

3.5.4 Sensitivity Analyses............................................................................................................................ 3-18

3.6 SULFUR REDUCTION TECHNOLOGY CONCLUSIONS .................................................................................... 3-24
iii

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

FIGURES AND TABLES 

No. Page

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Table 1-1. Major Economic Parameters......................................................................................................................................1-3

Table 2-1. FGD System Deployment in U.S...............................................................................................................................2-1

Table 3-1. Design Basis Used for Dry FGD vs. Wet FGD. Comparison....................................................................................3-1

Table 3-2. Typical PRB Coal SO2 Emissions Expected from FGD Technology........................................................................3-7

Table 3-3. FGD System Labor Requirements ...........................................................................................................................3-15

Table 3-4. O&M Cost Basis (both units combined)..................................................................................................................3-16

Table 3-5. Summary Comparison of Wet and Dry FGD Levelized Costs (yr. 2013) for White Bluff Units 1 & 2..................3-17

Figure 2-1. Relationship Between SO2 to Dry FGD and SO2 Reduction Efficiency ..................................................................2-3

Figure 2-2. Typical Dry FGD System.........................................................................................................................................2-4

Figure 2-3. Typical SDA (B&W)................................................................................................................................................2-8

Figure 2-4. Typical Pulse Jet Fabric Filter ................................................................................................................................2-10

Figure 2-5. Typical Wet Limestone FGD System.....................................................................................................................2-15

Figure 2-6. Typical Ball Mill for Large FGD System...............................................................................................................2-16

Figure 2-7. Typical FGD Scrubber with Absorption Tray........................................................................................................2-18

Figure 2-8. FGD Scrubber with Open-Spray Tower.................................................................................................................2-19

Figure 2-9. Typical Vacuum Belt Filter ....................................................................................................................................2-22

Figure 2-10. Typical Rotary Drum Vacuum Filter....................................................................................................................2-23

Figure 3-1. Impact of SO2 in Fuel on Levelized Cost ...............................................................................................................3-19

Figure 3-2. Impact of Rail Delivery on Levelized Cost ............................................................................................................3-20

Figure 3-3. Impact of Two Dry FGD Absorber Modules on Levelized Cost ...........................................................................3-21

Figure 3-4. Impact of Mercury Control with ACI for Future Hg-MACT on Levelized Cost ...................................................3-22

Figure 3-5. Impact of Mercury Control with ACI Ahead of COHPAC Baghouse for Wet FGD to Met Future Hg-MACT ...3-23

Figure 3-6. Impact of SO3 Control with Trona Injection for Future SCR Resulting in Increased Sulfuric Acid Emission......3-24
iv

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

APPENDIXES 

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

A. Dry FGD General Arrangement 

B. Wet FGD General Arrangement 

C. Dry FGD Capital Cost Estimate 

D. Wet FGD Capital Cost Estimate 

E. Financial Analysis Summary 
1-1

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

1. INTRODUCTION 

1.1 PURPOSE 

The purpose of the study was to select the flue gas desulfurization (FGD) process best suited for application at 

Entergy’s White Bluff Station Units 1 and 2. The most commonly used wet and dry FGD processes were evaluated 

relative to one another using a structured methodology to achieve that goal. The study developed conceptual 

designs, order of magnitude cost estimates, and economic analyses of adding wet or dry FGD systems. 

1.2 STUDY APPROACH 

The initial task for the study was to evaluate emission control technologies that might be applied to reduce SOX

emissions from Entergy’s White Bluff Station. The most commonly used wet and dry technologies were identified 

as potential solutions for SOX control for these units based on current configurations. The following is a list of the 

major activities that were performed in the conceptual design of the technologies described in this report. 
1-2

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

• Material balances and process flow diagrams were developed to identify how the White Bluff units 

currently operate and how the addition of SOX control technologies would change their operation. 

• Based on the material balances that were developed, preliminary sizing of various emission control 

technology equipment was done for SOX control technologies as well as balance-of-plant (BOP) 

equipment and structures. 

• General arrangement (GA) drawings were prepared for wet FGD and dry FGD to estimate 

approximate quantity of duct material. 

• Inputs for specific capital costs for wet FGD and dry FGD were developed by comparison with 

historical vendor budgetary quotations for each technology implementation. 

• Inputs for O&M costs were developed in parallel with Entergy. A detailed model projecting 

annualized costs for each unit over a 40-year study period was prepared for wet FGD and dry FGD. 

1.3 STUDY BASIS 

The basic data listed below were used as inputs to the study: 

• Unit Design Information. Unit size, boiler type, capacity factor, heat input, flue gas temperature, 

pressure profiles, and water quality. 

• Economic Information. Real interest rate, escalation rate, replacement energy and capacity 

charges, and process consumables. 

• Fuel Information. Basic fuel properties for Jacob’s Ranch Powder River Basin (PRB) coal. 

1.3.1 Unit Design 

S&L initiated its evaluation using the heat input to the boiler of each unit provided by Entergy to generate material 

balances. Heat input to the boiler is a primary parameter used to calculate the quantity of flue gas that would need 

treatment at each White Bluff unit. A team of S&L and Entergy analyzed the various heat input data and concluded 

that 8,950 mmBtu/hr would be anappropriate heat input for the design of the FGD system. This resulted in 

approximately a 5% margin on the Unit 1 heat input after the economizer modification and 1% margin on Unit 2 

after its economizer modifications in 2008. The amount of flue gas that needs treatment is one parameter used to 

size emission control technology equipment that would serve as input to the capital cost estimate. 

1.3.2 Economic Information 

Table 1-1 lists the major economic parameters used in the financial model. 
1-3

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Table 1-1. Major Economic Parameters 

Parameter Value 

Amortization life, years 40 

Interest rate for discounting, % 8.24 

Commercial service date Sept 2013 

Capacity factor, % 72.0 

Debt percentage in capital structure, % 41.97 

Preferred stock percentage in capital structure, % 4.44 

Equity percentage in capital structure, % 53.59 

O&M escalation rate, % 2.0 

Debt interest rate, % 6.34 

Preferred stock rate, % 5.99% 

Capital escalation rate, % 3.0 

Federal and state tax rate, % 39.225 

Equity return, % 9.90 

Annual property taxes and insurance, % 0.944 

AFUDC, % 8.24 

Tax depreciation schedule Amortized over 84 months 

Auxiliary electric power energy charge, $/MWh 47.00 

Ash disposal cost, $/ton 8.58 

Operating labor rate, $/hr 40.00 

Raw makeup water, $/1000 gal 0.92 

Cooling tower blowdown water, $/1000 gal 0.48 

Lime, $/ton 107.00 

Limestone, $/ton 38.00 

1.3.3 Fuel Information 

The study is based on burning typical PRB coal. Based on the coals submitted, a typical operating coal with a sulfur 

content of 2 lb SO2 /mmBtu was used for the design. The coal was based on a heating value of 8,725 Btu/lb. The 
1-4

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

economic evaluation for SO2 control technology was assessed at 2 lb SO2/mmBtu design sulfur and 0.8 lb 

SO2/mmBtu operating sulfur as a baseline. A sensitivity analysis was performed for design sulfur levels at 3 lb 

SO2/mmBtu (operating at 0.8 lb SO2/mmBtu) and 5 lb SO2/mmBtu (operating at 5 lb SO2/mmBtu) for wet FGD, 

and at 3 lb SO2/mmBtu for dry FGD. Dry FGD would not be competitive at 5 lbs SO2/mmBtu. 
2-1

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

2. SULFUR REDUCTION TECHNOLOGY EVALUATIONS 

2.1 PURPOSE 

The purpose of the sulfur reduction technology evaluations is to develop a conceptual design for retrofitting a wet 

or dry FGD technology for White Bluff Station, then to compare the economics of each technology, and finally to 

recommend the technology best suited for application. The economics identify the cost of SO2 removal based on a 

net present value (NPV) assessment and normalized cost for $/ton of SO2 removed. 

2.2 TECHNOLOGY DESCRIPTIONS 

FGD technology has been applied in the U.S. since the 1960s and, with the nearly 40 years of development, it is 

considered a mature technology. A wide range of FGD technologies is available. Table 2-1 lists the various types of 

utility power plant FGD installations in the U.S. As shown in this table, wet FGD, with either limestone or lime as 

the reagent, is the most prevalent, with almost 75% of the total flue gas scrubbing capacity. Dry lime FGD, 

typically used when sulfur levels are less than 2 lb SO2/mmBtu, is the next most selected technology with over 15% 

of all installations. This section discusses wet limestone FGD and dry lime FGD technology in detail. 

Table 2-1. FGD System Deployment in U.S. 

FGD Type Boiler Units (No.) Installed FGD Units (%) 

Wet limestone 105 48 

Wet lime 58 26 

Dry lime/SDA 35 16 

Sodium carbonate 9 4.1 

Dual-alkali 6 2.7 

CDS 5 2.2 

Wellman-Lord 4 1.8 

Mag-Ox 3 1.4 

Dry aqueous carbonate 1 0.5 
2-2

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

2.2.1 Lime Spray Dry FGD (LSD FGD) 

The LSD FGD technology was developed beginning in 1977, to serve users of low-sulfur coal who had to meet a 

requirement of only 70% SO2 removal. As the technology’s experience grew and matured, it demonstrated much 

higher performance capabilities and now can provide as much as 95% SO2 removal in many applications. 

Gradually, it has been adopted by users of medium-sulfur coals, and now is frequently considered for mediumsulfur coals of 3 lb/mmBtu SO2 content. Maximum spray dryer absorber (SDA) vessel size had an equivalent 

capability of 150 MW of flue gas in the initial installations, but absorber vessels have grown to an equivalent of 

350 MW of flue gas. 

2.2.1.1 Description of Process 

In an LSD FGD system, flue gas is brought into contact with lime slurry in the SDA vessel. This process can use 

(pulverized) hydrated lime (Ca(OH)2) or (pebble) quicklime (CaO); however, large quantities of lime are 

consumed, so the more economical quicklime generally is used at large utility installations. CaO must be hydrated 

before use. This hydration occurs in a slaker, where lime is mixed with water and slurry of fine lime particles 

results. The chemical reaction is as follows: 

CaO + H2O ↔ Ca(OH)2

SO2 absorption takes place in an SDA. Calcium reacts with the SO2 to form waste solids sulfate (CaSO4) and sulfite 

(CaSO3), as shown in the following chemical reaction scheme. About one-third of the waste is sulfate and twothirds is sulfite. 

CaO + H2O ↔ Ca(OH)2

Ca(OH)2 + SO2 +H2O → CaSO3 • 

1

/2H2O + 3/2H2O 

CaSO3 • 

1

/2H2O + 3/2H2O + 1/2O2 (flue gas) → CaSO4 • 2H2O 

The dried solids are entrained in the flue gas and exit the SDA, along with the fly ash, and are collected in a fabric 

filter. Most of the SO2 removal occurs in the spray dryer vessel itself, although some additional SO2 capture occurs 

in the downstream baghouse. A dry FGD without a fabric filter will be limited to about 75% SO2 removal, but with 

a fabric filter 95% SO2 removal is achievable. 
2-3

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

The SO2 removal efficiencies of the existing LSD systems range from 85-95%, depending on the SDA inlet SO2

concentration. The effectiveness of spray dryer technology decreases with fuel sulfur levels above 3 lb SO2/MMBtu 

(as shown in Figure 2-1). At higher sulfur levels, the amount of sorbent required for removal of SO2 from the gas 

stream increases substantially, and the economics generally favor wet scrubbing. The curve in Figure 2-1 represents 

the amount of SO2 reduction expected for an LSD system with a baghouse. This is a general guideline for 

application of LSD technology, and is derived from S&L’s in-house database on the technology’s performance, 

which is based on guarantee data provided from various suppliers of FGD systems. 

Figure 2-1. Relationship Between SO2 to Dry FGD and SO2 Reduction Efficiency 

70

75

80

85

90

95

100

0123456

lbs SO2/mmBtu

% SO2 Removed

The primary operating parameters that affect SO2 removal using LSD FGD are: 

• The lime stoichiometric ratio (SR) varies with the amount of SO2 in the SDA in the flue gas. The 

SR can range from 1.2 lb-mole lime/lb-mole of SO2 at the inlet to 1.6 lb-mole lime/lb-mole of SO2

at the inlet. An SR value of 1.2 is applicable for inlet SO2 values of less than 1 lb SO2/mmBtu, 

while the larger value is for inlet SO2 values greater than 2 lb SO2/mmBtu. 

• The flue gas temperature into the SDA is important. Temperatures above 300°F allow more water 

and lime to be injected with the flue gas. This increases SO2 removal and the utilization of the 

lime. If the inlet temperature is below 300°F, the efficiency will be reduced. 

• The flue gas temperature at the SDA outlet, also known as the approach to saturation 

temperature, is designed to be 30°F above the saturation temperature. Operating at a 20°F 

approach temperature can increase removal efficiency but at the risk of water condensation in the 

baghouse, which can cause operating problems. 

2.2.1.2 Discussion of Features 

Figure 2-2 depicts a typical dry FGD system. The LSD FGD includes several subsystems: 
2-4

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

• Reagent handling and preparation 

• Absorption in a spray dryer absorber 

• Particulate collection 

• Flue gas system and stack 

• Waste handling system and disposal 

Figure 2-2. Typical Dry FGD System 
2-5

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

2.2.1.2.1 Reagent Handling and Preparation 

Lime is conveyed by truck, barge, or rail to an enclosed storage silo. A detailed study will be performed if dry 

technology is selected for White Bluff. Utilities usually require a storage capacity of at least seven days, depending 

on the delivery method and lime source proximity. For delivery by truck, the maximum recommended silo height 

should be 120 feet if the truck’s onboard blowers are used for unloading. However, the lime supplier should verify 

the capability of the truck blowers to transport the lime. If the silo needs to be taller than 120 feet, a permanent 

pressurized blower system needs to be installed. 

For lime delivered by truck, silos are usually sized for a 7- to 14-day capacity, 7 days if the lime source is close to 

the power plant and 14 days if a distant source is used. A 14-day capacity silo with truck delivery is used for this 

study. The bulk storage silo feeds directly into the lime-slaking train and no transfer system is needed. Delivery by 

truck may not allow for competitive bidding to supply lime if one source is significantly closer to the plant. Rail 

delivery allows for more sources to be considered. 

For delivery by rail, larger quantities of lime are stored on site. Durations of 14 days or more have been the norm 

for most utilities. The strategy for selecting the storage capacity depends on the railroad used and the number of rail 

cars that the site can handle. Some utilities receive an entire unit train of lime, while others receive one-third or onehalf of a unit train. 

The lime silo has either a bin activator or a fluidizer to promote lime flow ability. A rotary feeder in series with a 

volumetric feeder supplies the lime to a slaker, where the pebble lime, CaO, is hydrated to Ca(OH)2. The slaking 

process is exothermic and the heat release helps to shatter the lime into fine particles. The slaked lime slurry then 

flows to a storage tank where it is held until it is needed by the atomization process. 

Truck-delivered lime will remain in large pieces when it enters the slaker, but lime pneumatically transferred 

several times is likely to be in a powdered form. The slaking water must be at least 60°F so the slaking process is 

not cooled and slowed down. The slaking water also must be less than about 190°F so that the slaking process does 

not boil. 

Slaker types that are used in this process include detention, attrition, horizontal ball mill, and vertimill slakers. The 

detention slaker consists of a vessel equipped with an agitator that disperses the heat released during the reaction. 

Without the agitator, high temperature areas may form resulting in steam formation that may damage equipment. 
2-6

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

The vessel is also fitted with a classifier section that separates the sufficiently slaked particles from the coarse lime 

particles. The larger particles are recycled back to the slaker vessel while grit material, consisting of inert material 

as well as uncalcined limestone and magnesium oxide particles, is removed. 

An attrition slaker is comprised of a vessel and a set of agitators with a common axle, which produce a counter 

current flow that induces lime particle interaction in order to speed up the slaking process. The main difference 

between detention slakers and attrition slakers is the degree of solids interaction. Attrition slakers may also be 

mated to grinding or grit removal equipment for impurity removal. 

In a ball mill slaker, pebble lime and water is added continuously to a horizontal vessel that contains grinding 

media, which allows grinding and slaking to occur simultaneously. The product flows through a classifier that 

separates the final slaked product from the coarse material, which is then fed back to the ball mill to be processed 

further. Due to the grinding function of the ball mill slaker, a grit removal system is not necessary. 

A vertimill slaker operates in a similar fashion to the ball mill slaker, with the exception that the vessel is vertically 

oriented and includes a double pitch helix that agitates the grinding media. A classifier system is also used to 

recycle the coarse product back to the grinding vessel. Similarly to the ball mill slaker, the vertimill does not 

require a grit removal system. 

The advantage of the ball mill type slakers is the less stringent requirements for quicklime size and slaking water 

quality, as well as eliminating the need for the grit removal system. Although a slaker type has not been specified, 

the horizontal ball mill was used in the cost evaluation for the slaking process. Reagent preparation with two 100% 

slurry trains is used for this study. Each train is made up of a solo, feeder, and slaker. The slurry is stored in a 

dedicated storage tank. 

2.2.1.2.2 Recycle Ash System 

A portion of the waste solids from the baghouse will be sent to the recycle silo. The recycle silo is located above the 

waste slurry preparation area. From the recycle silo, the dry waste flows to premix tanks where it is combined with 

water. The slurry overflows first to recycle holding tanks, and then overflows into recycle slurry storage tanks. The 

recycle storage tank solids concentration is approximately 40% by weight. This recycle system allows the lime to 

be passed through the SDA several times to reduce lime consumption. The recycle train is important in achieving 
2-7

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

high SO2 removal efficiencies. There is residual activity left in the lime after it has been passed through the system 

once; therefore, it is re-introduced to gain additional lime utilization. 

2.2.1.2.3 Spray Dryer Absorber 

The SDA is a vertical, open chamber with concurrent contact between the flue gas and lime slurry (Figure 2-3). The 

slurry is injected at the top of the tower using either a rotary atomizer or a dual-fluid nozzle, which produces fine 

droplets to absorb the SO2. In the process of evaporating the droplets, the flue gas is cooled from the absorber inlet 

temperature of approximately 318°F to an outlet temperature of 160-180°F depending on the adiabatic saturation 

temperature. The actual outlet temperature is chosen based on the optimum reagent utilization, the flue gas 

saturation temperature, and the required SO2 removal efficiency. The absorber typically will be operated at 30°F 

above the gas saturation temperature (also known as the approach temperature) to prevent solids deposition on the 

walls of the absorber and to avoid moisture condensing in the particulate collector. The residence time of the cooled 

flue gas in the SDA should be at least 10 seconds to ensure high removal efficiencies. Most current designs utilize a 

residence time of over 12 seconds. 
2-8

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-3. Typical SDA (B&W) 

Source: Babcock & Wilcox 

The slurry comes into contact with the flue gas inside the SDA vessel, and the slurry should be dry before it 

contacts the SDA wall. Corrosion of the SDA walls can occur if a high-chloride coal is fired; however, this is rarely 

a concern with Powder River Basin (PRB) coals. Because the flue gas exiting the SDA typically is held at 30°F 

above saturation, carbon steel ductwork is adequate and alloys are not needed. Therefore, the downstream ducts, 

baghouse, and chimney liner can all be made of carbon steel. Precautions should be taken around access doors and 

other penetrations where cool ambient air can leak into the duct and form cool spots in the SDA where acids in the 

flue gases can condense. In these locations, it is common to spray a coating over the carbon steel for a minimal 

amount of corrosion protection. 

The dry absorber does have some capability to remove mercury from the flue gas, but the mercury must be in the 

ionic form to be absorbed. PRB coal is low in chlorides and the mercury from firing PRB is not in the ionic form, 
2-9

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

but rather, is mostly in the elemental form. However, dry FGD has potential to remove significant amounts of 

mercury if the elemental form can be converted to the ionic form in the flue gas. Coal additives have completed this 

conversion of elemental to ionic mercury. Coal additives could be a halogen, such as bromine or iodine. Tests to 

date have shown that another halogen, chloride, is the least effective of these compounds, but bromine or iodine 

have been effective in utility tests. Dry FGD has the potential to capture 70-80% of the mercury in the PRB coal if 

additives are used. Additives are believed to be less expensive than powdered-activated carbon. 

The SDA vessel will have a discharge hopper on the bottom to allow any small material buildup on the walls to 

slide down and to be removed. 

2.2.1.2.4 Particulate Collector 

The SDA typically is located after the air heater outlet, and needs to be followed by a particulate collector, which is 

almost always a baghouse. Dry FGD systems usually are coupled with a fabric filter baghouse because SO2 removal 

efficiencies up to 95% are then possible. A substantial amount of the SO2 is removed in the baghouse because the 

lime rich product and fly ash remain on the surface of the bags and the flue gas is pulled through this layer of lime. 

This close contact between the flue gas and lime accounts for another 10-15% of the overall SO2 removal. 

A pulse jet baghouse (Figure 2-4) with an air-to-cloth ratio of 3.5 ft/min (1.1 m/min) typically is used downstream 

of a dry-FGD system on coal-fired units. The baghouse is provided with a spare compartment for routine 

maintenance. The waste is pneumatically conveyed to a waste storage silo with typically a 3-day storage capacity. 

The baghouse or ESP casing must be well insulated to contain the heat within the casing and to keep the interior 

skin temperature about 30°F above saturation. 
2-10

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-4. Typical Pulse Jet Fabric Filter 

Source: Wheelabrator 

2.2.1.2.5 Waste Handling 

The waste collected in the baghouse is pneumatically transported to a storage silo. A portion of the waste is 

recycled to increase the reagent utilization. The dry FGD waste is mixed in a pug mill with water to prevent dusting 

if being transported in open top (tarp covering) style trucks for disposal. Sale of the waste products from dry 

scrubbing is rare and the material is typically sent to a landfill. Dry FGD waste contains reacted calcium compounds 
2-11

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

and unreacted lime, Ca(OH)2. The waste has pozzolanic properties and when water is mixed with the waste, it cures into 

a low-grade concrete. Because this solid product is impermeable, disposal in a landfill is a safe practice. One plant in the 

U.S. forms pellets with the waste and sells them as gravel for fill or sub-base. 

2.2.1.2.6 Flue Gas System and Stack 

Ducts downstream of the SDA can be fabricated out of carbon steel, but the ducts and expansion joints must be 

insulated with insulation pillows to contain the heat in the flue gas and maintain the gas at about 30°F above 

saturation. The chimney liner typically is insulated but its exit can have cool ambient air pulled down into the top of 

the liner under certain atmospheric conditions. The inside of a carbon steel liner is typically coated in the top 

50 feet to negate any impact of sulfurous acid condensation. 

2.2.1.2.7 Staffing 

The conceptual design economic analysis includes 16 additional people for the O&M of the new dry FGD system, 

as summarized below. A detailed listing of the staffing cost can be found in Section 3.5.2. 

• Lime unloading will require a crew to move the rail cars or trucks through the unloader and to 

connect the equipment to each hopper. This crew will work one shift between five and seven days 

per week to unload the cars. 

• FGD process operations will require an operator to walk down the process equipment and check 

for malfunctions. The rotary atomizers will need to be switched on a 60- to 90-day cycle to clean 

their atomization wheels and perform other maintenance. Dual-fluid atomizers will be cleaned 

weekly. 

• Waste loading to truck or rail cars will continue as currently practiced for fly ash. Disposal of 

larger amounts of solids will require additional time for these activities. 

2.2.2 Wet Limestone FGD with Forced Oxidation (LSFO FGD) 

The term wet FGD refers to a system using an absorber that completely saturates the inlet flue gas with water. The 

flue gas typically is 300°F when it enters the absorber, then the gas is adiabatically cooled to a saturation 

temperature between 122-135°F. The flue gas exits the absorber at the saturation temperature. The saturated flue 

gas allows for quick mass transfer of the SO2 gas into the slurry droplets. The slurry droplets are a combination of 

limestone and water. Once SO2 is absorbed, it reacts with the calcium from the limestone and the reaction product is 

a solid precipitate. 
2-12

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Wet limestone FGD systems have been operating in utility applications since the 1960s. Early generations of wet 

FGD technology had internal scaling problems that caused the absorbers to be brought off line for cleaning every 

few months. To achieve acceptable availability for multi-unit use, many smaller absorbers were installed on one 

unit so that one absorber could be taken off line for cleaning and repair while the others handled 100% of the flue 

gas. Over the years, utilities learned to combat scaling problems using two technological advances. The first 

advance was to use forced oxidation of the precipitate in the absorber reaction tank, which effectively addressed the 

problem of scaling in the absorber. The second advance was to introduce most of the water needed by the process 

into the mist eliminators of the LSFO FGD. The water required for mist eliminator wash typically has less than 

1000 mg/L total dissolved solids and less than 50% saturated calcium sulfates. Service water from a well or lake 

usually is acceptable for this application. Cooling tower blowdown and ash pond water are not acceptable. Good 

water quality significantly reduces the plugging of the mist eliminators. 

These advances solved many of the chemistry problems and made the process much less complex. State-of-the-art 

wet FGD systems do not experience scaling issues. Spare absorber modules are rarely installed and single absorbers 

are routinely installed on large units. 

Early-generation wet FGD technology experienced significant problems with corrosion of the absorber metals. 

Absorbers were coated with rubber or flake glass lined to avoid corrosion, but these systems required very high 

maintenance. To avoid high maintenance and to minimize the corrosion in the absorbers, alloys later were used 

inside the absorbers. The alloys ranged from 317 L to C-276, depending on the level of chlorides in the absorber 

recycle slurry. Utilities have identified the reasons for the corrosion and have learned to make better selections of 

alloys within the absorber. Developers of alloys have also responded with newer, more corrosion-resistant and 

lower-cost alloys. Utilities have also learned that the chloride level is the most important parameter to monitor. 

Modern wet FGD systems use blowdown water from the absorber to control the chloride concentration in the 

scrubber slurry to within the capabilities of the materials of construction. These advances have allowed utilities to 

select wet FGD systems that will last for several decades with only routine maintenance. Again, this also allows 

utilities to use a single absorber for large units. 

Waste solids from early-generation wet FGD were difficult to handle and to dewater, and had no value to utilities. 

The change to forced oxidation chemistry allowed utilities to produce gypsum from the wet FGD waste solids, 

which does have some value in certain locations. The gypsum dewaters easily to 90% solids and can be easily 
2-13

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

transported. Gypsum can be washed to remove fly ash and/or chlorides so it can be used for wallboard 

manufacturing, or as a soil additive in agricultural areas. Waste solids that are land-filled are dense and inert. Issues 

such as leaching and ground water contamination are not a concern for land-filling gypsum. It has been shown that 

most gypsum is land-filled, but if either of the other two uses is applicable, the gypsum can be sold or given away, 

thereby avoiding the land-filling costs. 

Wet LSFO FGD systems are the predominant wet FGD technology used by utilities. It is most applicable for 

medium- to high-sulfur coals where removal of 95-99% of the inlet SO2 can be achieved. LSFO FGD is also 

effective on low-sulfur coals where it can remove 93-95% of the inlet SO2. Wet FGD systems are limited to a 

minimum outlet concentration of between 0.03-0.04 lb/mmBtu of SO2. Driving the concentration lower is not costeffective. 

In summary, the basic wet limestone scrubbing process is now reasonably simple and well-established. Recent 

advances in the wet limestone FGD process include design changes to promote SO2 absorption at high removal 

rates. After experiencing poor reliability in the first generation of this technology during the 1970s and early 1980s, 

wet limestone scrubber technology has matured and is now capable of meeting availability levels of 99%. 

Additionally, gypsum can now be recovered as a salable byproduct where feasible. Extensive operating experience 

has increased industry confidence in designing larger, more reliable limestone scrubber modules. Single absorbers 

treating 1,000 MW of the flue gas are in operation. In 1994, wet limestone scrubbers were used on 70 units, (35,100 

MWe of the total scrubbing capacity). Today, there are more than 100 operating limestone scrubbers, with more 

under construction to meet new emission criteria. LSFO FGD is a viable technology for any coal-fired boiler. 

2.2.2.1 Description of Process 

In an LSFO FGD system, flue gas containing SO2 is brought into contact with limestone-slurry droplets and the 

SO2 is absorbed into the water droplet. Within the droplet, the SO2 and calcium from the limestone (CaCO3) react to 

form calcium sulfite (CaSO3). As the slurry falls through the flue gas, it eventually falls into the reaction tank, 

where it is stored for a few minutes (typically 6 minutes of liquid residence) before being recirculated back into the 

flue gas stream. The reaction tank has agitators to keep the slurry in solution and also has oxidation air spargers to 

force-oxidize the reaction product. The calcium sulfite is force-oxidized to calcium sulfate and the final product is 

calcium sulfate dihydrate (CaSO4 • 2H2O), commonly known as gypsum. The reactions are: 
2-14

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

CaCO3 + SO2 → CaSO3 + CO2

CaSO3 + 1

/2O2 (flue gas) + 2H2O → CaSO4 • 2H2O 

Before the use of forced oxidation, the bisulfite ions would be recirculated through the absorber and would scaleout on the internals of the vessel. Force oxidizing the bisulfite ions turns them into a precipitate in the reaction tank 

so it cannot scale out onto the internals of the absorber. 

Most of the solids are recycled through the absorber several times, and a small bleed stream is sent to a dewatering 

step. Vacuum drum or belt filters are used to concentrate the bleed slurry stream to 85-92% solids. The water from 

this process is returned to the FGD process. If salable-grade gypsum is to be produced, the solids are washed with 

clean water to remove the chlorides. This water is also returned to the process. 

The absorber is very effective at removing hydrochloric acid (HCl) from the flue gas. The HCl reacts with the 

limestone and stays in solution as chloride ions. Chloride ions are very corrosive to ferrous-based metals, thus 

carbon steel is not an acceptable metal for construction of the absorbers. For chloride concentrations of 15,000 ppm 

or less, a new stainless steel alloy is being used, alloy 2205. This alloy is used for the lowest-capital cost absorber. 

All the internals can be made from this alloy, including supports, recycle grids, trays, and reaction tanks. In most 

cases, recycle piping is not made of alloy, but of fiber-reinforced plastic (FRP) with a wear-resistant coating. PRB 

coal has minimal chlorides to be collected, but if a moderate-sulfur coal with higher chlorides is to be considered, a 

higher quality alloy could be used at a greater cost. 

2.2.2.2 Discussion of Features 

A typical wet FGD system comprises several subsystems, including: 

• Limestone handling 

• Limestone slurry preparation 

• Absorber 

• Primary and secondary dewatering and byproduct handling 

• Ducts and chimney 

Each subsystem is tailored to the specific characteristics of the plant site based on emissions criteria and the sulfur 

content in the fuel. These subsystems are diagrammed in Figure 2-5, with the operations of each described below. 
2-15

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-5. Typical Wet Limestone FGD System 

Flue gas from

precipitator

or baghouse 

Limestone slurry scrubbing

absorbs SO2 to form CaSO3 

Crushed

limestone 

Air

Aeration oxidizes CaSO3

to form crystallized

CaSO4 • 2 H2O (gypsum)

Slurry withdrawn to remove gypsum 

Gypsum

solids

to filtration

Desulfurized flue gas to stack 

Slurry recirculated to sprays 

Limestone is wet-ground

to produce limestone slurry 

Filtrate

M

Water Hydroclone

ROTARY DRUM 

VACUUM FILTER

ABSORBER

BALL MILL

Fresh water

Mist eliminators washed

with fresh water 

Bypass

Day Bin

Gypsum

HORIZONTAL VACUUM BELT FILTER OR

2.2.2.2.1 Limestone Handling System 

Crushed limestone (typically, 3/4 x 0-inch or 1.91 x 0-cm) received at a plant typically is delivered by bottomdump railcars or trucks and is unloaded into a receiving hopper. It is assumed that limestone will be delivered by 

truck at White Bluff. The trucks will unload the limestone to an outdoor, uncovered limestone storage pile. There 

are two storage piles - one active pile (30 days’ storage) that feeds the reclaim hopper and one inactive pile that is 

used only if limestone deliveries are interrupted. A bulldozer is then used to move limestone between the two piles. 

Reclaim of the limestone from the bottom of the active storage pile is by underground reclaim hoppers equipped 

with vibrating belt feeders. The feeders supply the reclaim conveyor, which carries the limestone to the day silos 

located immediately above the wet grinding ball mills. Rain water around the active and inactive limestone piles is 

handled by installing a drain ditch around the piles where the water can be collected. 
2-16

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

2.2.2.2.2 Limestone Slurry Preparation System 

Preparation of the limestone slurry involves wet grinding the limestone in a horizontal ball mill. The limestone 

received on site is similar to gravel. The limestone day bins and gravimetric feeders deliver the limestone to a 

2 x 100%-capacity ball mill system for both units. Figure 2-6 shows typical ball mills. One ball mill runs continuously, 

while the second ball mill provides 100% spare capability. The ball mill grinds the limestone and discharges it into a 

small receiving tank that is then pumped through hydroclone classifiers. The limestone that is 95% less than 325-mesh is 

ready for use and sent to a storage tank, but the larger particles are returned to the ball mills for further grinding and size

reduction. Two 100%-capacity classification pumps are used to ensure high reliability of the classification system. 

Process makeup water or recycle water is added to the ball mills to produce 70% by weight solids slurry. The slurry 

classification process produces 30% by weight solids slurry, which is stored up to 24 hours until it is fed as reagent 

makeup into an absorber. The slurry concentrations are measured using nuclear density meters. The ball mills are 

rubber-lined to reduce erosion of the mill internals. Steel balls are added as needed to replenish the balls in the mill. 

Since White Bluff is located in a warmer climate, the reagent preparation system will not need to be in a building to 

protect the equipment and staff from the weather. 

Figure 2-6. Typical Ball Mill for Large FGD System 

2.2.2.2.3 Absorber System 

Figure 2-7 depicts a typical absorber (B&W) utilizing a vertical spray/tray tower concept, with counter-current 

contact between the flue gas and scrubber slurry. This counter-current type is the most commonly used absorber in 

the utility industry. Other absorber types available include jet bubbling reactor and co-current/counter-current flow. 
2-17

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

First-generation absorbers relied on packing to provide the mass transfer, but in conventional absorbers the mass 

transfer occurs in the tray and in the open-spray zone. Some vendors rely on the sprays to provide the mass transfer, 

while other vendors use the tray for mass transfer. 

The tray is a horizontal perforated plate with a two-foot-tall egg crate on top that causes the slurry to form a 

several-inch froth layer on top of the tray. Flue gas that is forced up through the tray, comes in contact with this 

froth, and then gives up its SO2 to the slurry. When a tray is present, most of the sulfur collection occurs at the tray 

and the spray levels do less of the sulfur collection. One advantage of the tray is that it smoothes the upward flow 

of flue gas, evenly distributing the flow so the entire absorber area is used for sulfur collection. Including a tray in 

the design allows reduction of the liquid-to-gas (L/G) ratio. B&W and Siemens both use trays. 

An open-spray tower is a second popular absorber design. This type of absorber relies on several spray levels to 

create enough droplets to carry out the necessary mass transfer. The L/G ratio for an open-spray tower is greater 

than for a tray, and the uniform downward flow of slurry is responsible for spreading the upward flow of flue gas 

for uniform flow. Open-spray towers use a baffle around the inside circumference of the absorber to prevent gas 

flow from bypassing the spray zone. Designers of this type of absorber point out that there are no internals in the 

absorber to corrode or scale. Alstom and Babcock Power Inc. both use open-spray towers. Figure 2-8 depicts 

Alstom’s open-spray tower. 
2-18

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-7. Typical FGD Scrubber with Absorption Tray 

Source: Babcock & Wilcox 
2-19

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-8. FGD Scrubber with Open-Spray Tower 

Source: Alstom 

After falling through the spray zone, the slurry accumulates in the reaction tank. Modern absorbers integrate the 

reaction tank into the bottom of the absorber, whereas earlier-generation FGD systems used a separate external 

tank. The tanks hold the slurry for at least 15 hours (solids residence time) to allow the reaction between the 

limestone and SO2 to complete and let gypsum crystal grow above 20 microns. The reaction tank is agitated to keep 

the solids in suspension and air is forced into the reaction tank to force-oxidize the CaSO3 in the slurry. Fresh 

limestone is added to the tank so there is an excess of calcium and all sulfur is reacted. The retention time in the 

reaction tank allows all the sulfite to react with oxygen so the solution is not supersaturated with sulfite and bisulfite ions. Without the forced oxidation step, the absorber would be susceptible to scaling and would need 

frequent cleanings. With forced oxidation, there is no need to clean the absorbers of scale that could disrupt 

absorber performance. 
2-20

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

The forced oxidation air is supplied by a set of compressors in the absorber building. Compressed air is injected 

below the reaction tank agitators through a sparger network to achieve greater than 99% oxidation of calcium 

sulfite (CaSO3) to calcium sulfate (CaSO4). A 3:1 stoichiometric ratio (SR) of oxygen to SO2 is used to size these 

air compressors. 

From the reaction tank the slurry is pumped back into the absorber’s spray zone. High-horsepower pumps are used 

for the recycle. Conventional absorbers have at least one spare recycle pump to provide high availability of the 

absorber. Slurry is sprayed through several headers that span the diameter of the absorber. Slurry is abrasive and the 

spray nozzles are erosion-resistant. Occasionally, a piece of scale can become lodged in the spray nozzle, causing 

pluggage or sending the flow in an unpredicted direction, so many smaller nozzles are used. The spray header 

material is either alloy or FRP, with the latter gaining more use in recent absorber installations. 

Above the spray zone is the mist eliminator, which removes the entrained slurry droplets so they do not exit the 

absorber and create particulate emissions leaving the chimney. The mist eliminator must be washed with clean 

water to remove limestone deposits. Early-generation wet FGD systems attempted to use cooling tower blowdown 

or other wastewater, but this caused plugging of the mist eliminators. When high-quality water is used, plugging is 

virtually eliminated. 

The absorber must be constructed of materials that resist corrosion, erosion, and scaling. To reduce corrosion when 

firing PRB coal, an A-2205 SS alloy can be used so long as the chlorides in the recycle slurry are maintained 

between 8,000-15,000 ppm with typical chloride less than 12,000 ppm. PRB coals usually have a minimal amount 

of chloride so this is usually the highest alloy that needs to be considered. The absorber inlet duct is an especially 

corrosive environment because of the wet/dry interface that occurs when some of the slurry deposits on the inlet 

floor of the duct. To combat this highly corrosive environment, the inlet duct is made of C-276 from the absorber 

back about 10 feet. The outlet duct to the chimney is also a location subject to corrosion and either C-276 or FRP is 

used for this duct. FRP would be used if the unit is installing an FRP liner in the chimney. If FRP is not used in the 

chimney, then a C-276 clad duct would be likely. 

Wet absorbers generally are ineffective at collecting particulate. If a high-efficiency precipitator or baghouse is 

ahead of the absorber, the amount of particulate emissions into the absorber is anticipated to be the same as out of 

the absorber. A high-efficiency particulate collector ahead of the absorber is beneficial to wet FGD chemistry 

because fly ash can add ions to the recycle slurry solution that can interfere with the absorption process. 
2-21

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Because wet FGD systems absorb HCl from the flue gas at 99% efficiency, a minimal amount is released to the 

environment. Wet FGD systems do not collect SO3 very effectively, and they can cause SO3 to condense as very 

fine droplets that can result in a blue plume immediately after the flue gas exits the stack if the concentration of SO3

exceeds 7-10 ppm. Fortunately, when PRB coal is fired, the amount of SO3 in the flue gas is minimal and a colored 

plume will not result. Installation of an SCR will increase SO3 concentrations. 

The wet absorber does have some capability to remove mercury from the flue gas, but the mercury must be in the 

ionic form to be absorbed. PRB coal is low in chlorides and the mercury from firing PRB is not in the ionic form, 

but rather, is mostly in the elemental form. However, a wet FGD has potential to remove significant amounts of 

mercury if the elemental form can be converted to the ionic form in the flue gas. Coal additives added to the coal 

have completed this conversion of elemental to ionic mercury. Coal additives could be a halogen, such as bromine 

or iodine. Tests to date have shown that another halogen, chloride, is the least effective of these compounds, but 

bromine or iodine have been effective in utility tests. A wet FGD has the potential to capture 70-80% of the 

mercury in the PRB coal if additives are used. Additives are believed to be less expensive than powdered-activated 

carbon. 

2.2.2.2.4 Primary and Secondary Dewatering and Byproduct Handling Systems 

The bleed stream from the reaction tank is pumped to a set of hydroclones for primary dewatering. The hydroclone 

overflow is recycled back into the scrubber. The hydroclone underflow, containing 50% solids, is fed to a belt filter 

for secondary dewatering, as shown in Figure 2-9. Belt filters are designed to achieve 90% solids in the gypsum 

byproduct to meet the requirements of gypsum buyers, if the gypsum is being sold to the wallboard industry. The 

gypsum cake is washed with fresh water on the belt filters to remove any residual chlorides to a level typically less 

than 100 ppm by weight chloride in the dry solids. The wash water used for gypsum cake washing should not 

contain chlorides more than 50 ppm if the product is intended for sale to a wallboard manufacturer. The filtrate 

from the horizontal belt filter is returned to the process. If gypsum is disposed in a landfill, a lower-capital-cost 

drum filter could be used. The drum filter requires more maintenance than a belt filter. For example, it can take an 

entire shift to change the filter cloth on a rotary drum. Also, agitators can break frequently due to accumulation of 

large particles that may enter the drum pan. The rotary drum does not accommodate changes in slurry concentration 

very well. Since the cloth is manually bolted in, it wears faster than a belt filter. A typical rotary drum filter is 

shown in Figure 2-10. 
2-22

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-9. Typical Vacuum Belt Filter 

Slurry feed

Cake wash

Product

discharge
2-23

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 2-10. Typical Rotary Drum Vacuum Filter 

As mentioned earlier, chlorides are absorbed from the flue gas and they concentrate in the recycle slurry solution. A 

small blowdown stream may be required to remove chlorides and other contaminants from the process. If the 

gypsum is not being sold, washing the filter cake is not required and chloride-control of the dewatering process is 

significantly less complicated. Less costly rotary drum vacuum filters can be used if the gypsum is to be sent to a 

landfill, although a water treatment facility will still be necessary to treat the blowdown from the absorber. Landfill 

disposal requirements are very site-specific, and depend on parameters such as the actual chemical makeup of the 

gypsum waste product, local climate, and soil conditions. 

Dewatered gypsum from the belt filter is deposited on a collecting conveyor, then conveyed out of the dewatering 

building and stacked on the ground. The gypsum is then loaded into trucks with a front-end loader and then hauled 

away. 

Gypsum also has potential for reuse, e.g., feedstock for wallboard manufacturing. For this to be an attractive form 

of reuse, a large quantity of gypsum is needed. Utilities with 500 MW gross or more of capacity and firing highsulfur coal are likely candidates to pursue wallboard manufacturing options. These type plants would also need to 

be relatively near markets that would be in demand of large quantities of wallboard, such as urban areas. Gypsum 

can also be used for agricultural purposes, as a soil additive, or as an additive to concrete. Gypsum’s inert nature 

renders it viable for land-filling. 
2-24

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

2.2.2.2.5 Staffing 

The conceptual design economic analysis includes 21 additional people for the O&M of the new wet FGD system, 

as summarized below. A discussion of the staffing costs can be found in Section 3.5.2. 

• Limestone unloading will require a couple of personnel to move the limestone into the reclaim 

hopper underneath the active pile and to move the rail cars through the unloader. 

• FGD process operations will require an operator to walk down the process equipment and check 

for malfunctions. Typical maintenance activities for the FGD system would involve the 

conveyors, ball mills, including changing of ball load, recycle slurry pumps, mist eliminator, spray 

headers and nozzles, booster fans, hydroclones, rotary drum filters, and waste conveyors. 

• Lab Technician/System Engineer for chemistry monitoring. 

• Waste loading to trucks will require additional operators. The larger amounts of solids requiring 

disposal will also require more time for this activity. 
3-1

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3. COMPARISON OF LSD AND LSFO FGD PROCESSES 

3.1 DESIGN BASIS 

S&L developed and issued to Entergy separate design basis documents for dry and wet FGD, as summarized in 

Table 3-1. 

Table 3-1. Design Basis Used for Dry FGD vs. Wet FGD. Comparison 

Parameter Value 

Net MW 844 each 

Heat input to boiler, mmBtu/hr 8,950 

Coal type 100% PRB 

Coal composition 

Carbon 49.92% 

Hydrogen 3.58% 

Nitrogen 0.67% 

Sulfur 0.87% (2.0 lb SO2/mmBtu) 

Oxygen 12.01% 

Moisture 27.72% 

Chlorine 0.02% 

Ash 5.2% 

HHV, Btu/lb 8,725 

Flue gas flow, acfm 3,685,000 at 318°F 

SO2 removal efficiency 95% 

Dry FGD-Specific

Lime stoichiometric ratio 1.1 

Lime quality 90% CaO 

Lime storage silo 14 days (both units) 

Day bin storage 24 hours (both units) 

Slakers 2 x 100% (both units) 
3-2

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Parameter Value 

Absorber 3 x 33%, carbon steel (each unit) 

Booster fans 2 x 50% (each unit) 

Waste recycling 1 x 100% (each unit) 

Waste storage 3 days, 1 x 100% (each unit) 

Stack No modifications 

Reagent, ton/hr 8.4 (both units) 

Trucks per day 10 

Waste, ton/hr 17.8 (both units) 

Trucks per day 22 

Makeup water, gpm 2,100 (both units) 

Wet FGD-Specific 

Liquid-to-gas ratio 80 

Limestone stoichiometric ratio 1.03 

Limestone quality 90% CaCO3

Limestone storage pile 30 days (both units) 

Day bin storage 24 hours (both units) 

Ball mills 2 x 100% (both units) 

Absorber 1 x 100%, alloy 2205 (each unit) 

Booster fans 2 x 50% (each unit) 

Primary dewatering Hydrocyclones, 2 x 100% (both units) 

Secondary dewatering Drum filters, 2 x 100% (both units) 

Stack 35-foot diameter, 1003-foot height FRP liner (each unit) 

Reagent, ton/hr 11.7 (both units) 

Trucks per day 15 

Waste, ton/hr 22.6 (both units) 

Trucks per day 27 

Makeup water, gpm 2,520 (both units) 
3-3

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.2 GENERAL ARRANGEMENT 

3.2.1 Lime Spray Dryer (LSD) FGD 

S&L developed general arrangement (GA) drawing of major equipment and structures for the White Bluff Station 

dry FGD system. The GA drawing for the LSD FGD is presented as Appendix A. This GA was the preferred 

arrangement primarily because it minimized the ductwork length between the SDA outlet and the baghouse inlet, 

and eliminated turns or elevation changes in the duct. This offers long-term maintenance benefits because the 

shorter duct length results in minimizing the amount of solids that can drop out and accumulate on the duct floor. 

Implementing the GA will require demolishing White Bluff Station’s Ash Handling Maintenance Building due to 

the location of the new spray dryers, and building a new building directly north of the FGD system. 

Two lime silos are arranged near the lime preparation area and are sufficiently sized to store the reagent for 14 days 

of operation. The lime in the bulk storage silo will be pneumatically blown to a day silo located in the reagent 

preparation area. Because the reagent preparation area is located near the SDAs, lime slurry will need to be pumped 

only a short distance to the top of each SDA. 

The recycle portion of the dry FGD process will be local to the prospective unit and not included in the combined 

reagent preparation area. A set of silos will be located near the baghouse inlet to receive baghouse recycle fly ash 

that will be slurried and re-injected into the SDAs. 

Two new booster ID fans will be placed in series with the existing ID fans. The booster fans will be sized to handle 

the additional pressure drop associated with the dry FGD. 

3.2.2 Wet FGD 

S&L developed GA drawings of major equipment and structures for the White Bluff Station wet FGD system. 

Appendix B is a GA showing the major equipment and structures for a wet LSFO FGD system. 

The GA was developed based on truck delivery of limestone to the active pile. The limestone unloading, stack-out, 

storage in an active pile, storage in an inactive pile, and reclaim are all common to both units. The reagent 

preparation area is shown on the GA and will house the ball mills, classifying equipment, storage of the final slurry 

product, and equipment to feed the reagent to the absorber. 
3-4

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

The absorber vessel for each unit is located to the east of the unit. The duct located after the existing ID fans is the 

location of the tie-ins for the wet FGD for each unit. A rather short duct is added to divert the flow to each absorber 

area. Two new booster ID fans are then shown to feed a single absorber, which then feeds a single new chimney per 

unit. The old chimney could be demolished or capped and left in place. If this is the case, routine maintenance will 

need to be performed on the chimney for structural integrity and potential deterioration. The arrangement for the 

wet FGD flue gas path is relatively straightforward. 

The dewatering system is common for both units and located north of the units. This location allows easy access for 

the trucks that will haul away the gypsum byproduct. 

The existing ESP and fly ash system will remain as is and are unaffected by the retrofit of the wet FGD, because the 

wet FGD is downstream of the ESP. 

3.3 COMPARISON OF SYSTEM FEATURES 

3.3.1 Absorber Vessel 

The wet FGD system has an advantage in that a single absorber can be used at each unit at White Bluff. Single 

absorbers have been built for up to 1,000 MW of flue gas. A single absorber per unit greatly reduces the capital cost 

of a wet scrubber. 

A dry FGD system uses a spray dryer. For White Bluff Station three SDAs were considered per unit. Some utilities 

are starting with SDAs that could be sized for one-half of a White Bluff Station unit’s flow. The feasibility of a 

SDA vessel of this large a size has not yet been proven. 

A single vessel allows the system to be designed without dampers. This is a significant cost saving and reduces 

O&M of dampers and auxiliary power for heated seal air. With two or more vessels, dampers will be included to 

allow one absorber to be taken off line for repairs. Without these dampers, the reliability of a two- or three-absorber 

system would not be an improvement to a single-absorber system. 

Absorber material of construction favors dry FGD systems, because they can use carbon steel absorbers without 

concerns about corrosion. Wet FGD systems must be built out of corrosion-resistant alloys. With PRB coals, a 

lower-cost, lower-grade alloy can be used, e.g., A-2205 SS, because recycle chloride concentrations of less than 
3-5

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

15,000 ppm are expected inside of the vessel. This alloy is a fairly new material that only recently is being used on 

FGD systems. Additionally, the wet/dry interface at the wet absorber’s inlet will need alloy C-276 to protect this 

very corrosive location. In general, wet FGD materials are more expensive than dry FGD materials. 

The single-absorber vessel represents cost savings in wet FGD but the carbon steel materials of construction are an 

advantage for dry FGD. Both of these features have been considered in the capital cost estimates completed for 

these two technologies. 

3.3.2 Chimney 

Wet FGD technology typically is installed between the outlet of the existing particulate collector and chimney. 

However, most retrofit wet limestone FGD units are unable to use the existing chimney, as the chimney typically 

would have been designed for hot flue gas at between 70-100 ft/sec exit velocities. To accommodate saturated flue 

gas from a wet limestone FGD system, wet stacks typically are designed using a corrosion-resistant flue with a 

design gas velocity of 55 ft/sec or less. Adding a new chimney for each unit is deemed more cost-efficient as 

opposed to a common chimney with dual flues for both units, due to complications with duct work around the 

existing coal conveyor. Using one chimney for each unit will minimize expensive ductwork downstream of the 

absorber that typically requires either FRP- or C-276-clad liners to avoid corrosion. The capital cost estimate 

includes two new FRP-lined chimneys. Reuse of the existing chimney is often a significant cost advantage for a dry 

FGD system. 

3.3.3 Chemistry 

The wet FGD system has a more complex system operating chemistry to monitor than the dry FGD. The wet FGD 

scrubber vessel liquor chloride content must be monitored to prevent absorber corrosion. The pH level must also be 

monitored to maintain high SO2 removal efficiency and minimum corrosion. Scale oxidation rate is monitored to avoid 

scrubber scaling and plugging. However, because the chemistry is relatively constant, it is unusual to have an upset that 

causes equipment shutdown. 

The dry FGD system does not require as much chemistry monitoring, but it requires monitoring of the slaking and 

recycle trains. The recycle trains mix dry recycled fly ash collected from the baghouse with water, an inherently difficult 

task. The recycle system needs frequent attention from operators and the trains are taken out of service every week or 
3-6

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

two. Generally, a dry FGD system needs to be monitored more carefully from hour to hour, whereas, a wet FGD system 

operates at a fairly steady pace. 

3.3.4 Chloride Blowdown 

The wet FGD system absorbs HCl from the flue gas and it is concentrated in the recycle water. The absorber can be 

designed for up to 15,000 ppm of chloride without corrosion problems. To limit chloride buildup, some water is blown 

down to remove chlorides. This water is often mixed with other plant water and allowed to discharge with other 

effluents. If commercial-grade gypsum is to be produced, there will be a wastewater stream off the belt filters that will 

have to be treated. If the product is to be land-filled, the wastewater will be discharged with the blowdown stream and 

will have to be treated as well. Based on the chloride level of 200 ppm in the fuel and the chloride level up to 390 ppm in 

the blowdown water, there will be always be a blowdown from the wet FGD. The cost estimate therefore includes the 

wastewater treatment facility. 

Dry FGD does not have a wastewater blowdown stream or a wastewater treatment facility. 

3.3.5 Water Consumption 

System design calculations for wet and dry FGD systems at White Bluff Station predict that a wet FGD system would 

consume 1,260 gallons per minute (gpm) per unit and the dry FGD system 1,050 gpm per unit, while burning 2 lb 

SO2/mmBtu coal. The wet FGD system is estimated to have a waste discharge of 43 gpm per unit that would need to be 

chemically treated to precipitate out the metals for the base case. This 43-gpm level can be reduced, if necessary and is 

based on land-filling the gypsum. The dry FGD system does not have a wastewater discharge. 

3.3.6 SO2 Control 

The FGD systems considered have unique capabilities to remove SO2. As previously stated, a wet FGD is known to 

give lower outlet SO2 emissions compared with other FGD systems. Each of the systems can achieve lower 

emissions when the unit is at a steady load with a consistent coal. However, as load changes or upsets in the boiler 

operations occur, or as coal sulfur varies, so too, does the outlet emissions of the FGD. Table 3-2 summarizes the 

general capabilities of the FGD technologies considered in the study. 
3-7

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Table 3-2. Typical PRB Coal SO2 Emissions Expected from FGD Technology 

Parameter Lime SDA FGD Wet LSFO FGD 

Lowest achievable SO2 emission (lb/mmBtu) 0.06 – 0.08 0.03 – 0.06 

Achievable 24-hour average (lb/mmBtu) 0.12 – 0.15 0.09 – 0.10 

Achievable 30-day average (lb/mmBtu) 0.10 – 0.12 0.07 – 0.10 

Achievable annual average (lb/mmBtu) 0.08 – 0.10 0.06 – 0.08 

3.3.7 Particulate Control 

Particulate control is a pivotal issue in selecting dry or wet FGD systems because, although it is not a necessary part 

of the wet FGD process, it is integral to a dry FGD system. Recently, wet FGD suppliers have provided particulate 

control guarantees as low as 0.015 lb/mmBtu with inlet particulate up to 0.12 lb/mmBtu. Since White Bluff Station 

is equipped with an existing ESP, the particulate emissions would be maintained with wet FGD or lowered to 

0.015 lb/mmBtu. The baghouse for the dry FGD would be designed to lower the emission to 0.012 lb/mmBtu 

giving an advantage to the dry FGD system over the wet FGD. 

As for condensable particulate matter, the wet FGD system promotes the condensation of sulfuric acid mist more 

than the dry system due to the lower outlet temperature. For either system the condensable particulate is found 

assuming 0.8% of the SO2 in the boiler is converted to SO3, the outlet of the stack would contain 2 ppm of SO3, or 

63 lb/hr; converting this emission to a sulfuric acid mist basis gives 77 lb/hr of condensable particulate. Even with 

the addition of SCR on the unit, the additional conversion of SO2 to SO3 would result in 7 ppm of SO3, or 289 lb/hr 

of sulfuric acid mist. This level is greater than the current operating permit limit of 261 lb/hr of condensable 

particulate matter, a permit revision would then be necessary once an SCR is in place. 

Fugitive emissions and additional emission points from ancillary equipment must be taken into account when 

choosing an FGD technology. The wet FGD process requires open limestone and gypsum piles, which adds a 

fugitive emission source due to the wind erosion on the open pile. In addition, the truck loading/unloading of the 

limestone and gypsum adds a second fugitive emission source. Contrary to this, the dry FGD process does not add 

any fugitive emission sources due to the reagent or product, because this material is pneumatically conveyed to the 

silos. 
3-8

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Similarly to the fugitive emission sources, several transfer and emission point sources are added to each FGD 

system. Storage silos, common to both types of FGD systems, contribute to particulate emissions, but are controlled 

by vent filters by up to 95%. The reactant preparation building, common to both types of FGD, also contributes to 

particulate matter emissions, but ventilation fans reduce these emissions by up to 75%. Lastly, the wet FGD system 

conveys limestone and gypsum byproduct via belt conveyors, which add potential emission points, but dust 

suppression system are available that can reduce these emissions by up to 75%. 

3.3.8 SO3 Removal 

Sulfur trioxide (SO3), which condenses to sulfuric acid aerosols in an FGD system, is removed efficiently (greater 

than 90%) with a dry FGD/baghouse equipment combination. Wet scrubbers have less affinity for acid mist and 

they typically capture between 25-50% of sulfuric acid aerosols, according to FGD suppliers. Alkali injection (i.e., 

Trona) upstream of a particulate collection system or even the addition of a wet ESP would be required for a wet 

limestone FGD system to achieve the same level of acid mist removal as the inherent removal in a dry FGD system. 

S&L would expect alkali injection to be considered BACT for acid mist. The emission of sulfuric acid mist, if 

above a threshold value of 7-10 ppm at the stack, may result in a pale blue plume visible after the water vapor 

plume dissipates. White Bluff Station fires PRB coal, which has low SO3 concentrations, so a colored plume is not 

expected. 

The current SO3 emission from the White Bluff units is estimated to be 3 ppmvd (@3%O2) or less with 2 lb 

SO3/mmBtu PRB fuel (assuming 0.6% oxidation in boiler, 25% removal across air heater, and 2 ppm across ESP). 

With wet FGD, the outlet concentration will be approximately 2 ppmvd (@3% O2) with 25% removal efficiency 

and with dry FGD, the concentration will be less than 1 ppmvd (@3%O2). The advantage of a dry FGD could be 

realized only in the case of a future SCR system. If the future SCR system is designed with 3% SO2–to-SO3

oxidation (only with PRB coal), the emissions from the wet FGD could be as high as 9-12 ppmvd SO3, compared to 

dry FGD, which could be limited to 2 ppmvd (@3% O2). 

3.3.9 Mercury Collection 

The dry FGD with baghouse system removes ionic mercury from the flue gas. For mercury capture with PRB coal 

which would have greater than 80% mercury as elemental mercury, an activated carbon injection (ACI) system or 
3-9

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

the fuel additive injection to convert elemental mercury into ionic mercury will be required. ACI systems inject 

halogenated activated carbon before the SDA and up to 90% removal is expected with a 2 lb/mmacf feed rate. 

Similar to dry FGD, wet FGD can remove oxidized mercury. Unfortunately, mercury in PRB coal usually is in the 

elemental state, which is not as easily removed. To use the wet FGD capability to remove mercury, a halogenated 

(chloride or bromide based) fuel additive can be used that converts the elemental mercury to the oxidized form. The 

mercury can then be captured by the wet FGD. An overall removal of 70-80% is possible with wet FGD. To 

achieve higher removal efficiency, an additional activated carbon injection system ahead of the ESP or ahead of a 

polishing baghouse may be required. 

The technology of converting elemental mercury to oxidized mercury still needs to mature. However, if this 

technology develops as anticipated, an ACI system may not be required if wet FGD systems are installed on the 

White Bluff units. 

On February 8, 2008, the U.S. Circuit Court of Appeals for the District of Columbia rejected the strategy of 

regulating mercury emissions through a cap-and-trade program and therefore vacated the Clean Air Mercury Rule 

(CAMR). The rejection of the cap-and-trade regulation will compel the U.S. EPA to develop a new set of standards 

for electric generating units to reduce mercury. It is uncertain when this will occur, however it is believed it will 

take several years. 

3.3.10 Preliminary CO2 Considerations for Dry and Wet FGD 

The area needed for the CO2 removal system (physical footprint) for a wet FGD is somewhat smaller than for a dry 

FGD. This is primarily due to the fact that CO2 removal on a unit equipped with a dry FGD requires adding a wet 

chimney since the gas has to be further cooled before entering the CO2 equipment. The CO2 equipment requires a 

pre-scrubber/cooler to obtain SO2 emissions below 10 ppm, which is the maximum inlet SO2 concentration into a 

CO2 absorber to reduce sulfur contamination. Therefore treatment to remove additional SO2 would be needed on 

both systems. Since dry FGD cannot achieve SO2 emissions as low as wet FGD, higher operating cost would be 

required for the pre-scrubber connected to the dry FGD. The CO2 physical footprint includes areas for the CO2

removal processes: the pre-cooler and absorber area for separating the CO2 from the gas stream, a regenerator area 

to renew the scrubber solution, and a compressor area for storage of the CO2. 
3-10

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

A wet FGD system produces more CO2 than a dry FGD due to the chemical reactions with calcium carbonate 

(CaCO3), the release of one mole of CO2 is accomplished for every mole of SO2 absorbed. The CO2 is formed 

through the decomposition of limestone (CaCO3) to form calcium sulfite (CaSO3). CO2 makes up approximately 

44% by weight of the limestone, depending on purity. Therefore for each ton of limestone consumed, there will be 

approximately 0.44 tons of CO2 formed. With the operating case of an inlet concentration of 0.8 lb SO2/mmBtu a 

total of 11.7 tph of limestone would be consumed for both units combined, which translates to 5.1 tph of CO2, from 

both units. This totals 45,100 additional tons of CO2 per year from White Bluff. To put this in perspective, the 

combustion-based CO2 emissions for the White Bluff units total slightly over 16 million tons per year combined. 

Therefore, the CO2 produced from the presence of CaCO3 is very minimal when compared with the CO2 emissions 

from the combustion of coal. The combustion of the coal produces roughly 940 tph per unit at White Bluff Station, 

while the added CO2 produced in the wet FGD system is less than 1% of this total. 

The dry FGD uses lime, which has no added production of CO2 in its use. Noteworthy is that lime is a product of 

limestone and even though dry FGD is not emitting CO2, the kiln that is producing the lime (CaO) generates CO2

from the gas driven off the limestone when heating it to 2000-2400°F. One mole of CO2 is driven off for each mole 

of limestone consumed; this results in more CO2 being produced in forming lime than it does in using limestone as 

a reagent. Additionally, there is fuel consumed to produce the heat, which emits CO2, and the motors that drive the 

mechanical portion of the process require energy; this drives the CO2 emitted from the life cycle of lime to a level 

exceeding limestone, but the release point is moved to the lime supplier and Entergy would not be concerned with 

this emission. 

3.4 COMPARISON OF CONSUMABLES AND WASTES 

3.4.1 Power Consumption 

The O&M costs presented herein account for power consumption. The wet FGD consumes 8.9 MW and the booster 

fan consumes 5.1 MW, for a total of 14.0 MW per unit. The dry FGD consumes 4.6 MW and the booster fan 

contributes 6.8 MW, for a total of 11.4 MW per unit. When a 3 lb SO2/mmBtu coal is fired, the total power 

consumption is increased to 16.3 MW for the wet and 11.8 MW for the dry system. Overall power consumption is 

lower for the dry FGD system than for the wet FGD system. 
3-11

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.4.2 Reagent Consumption 

Dry FGD systems use a more expensive reagent (quicklime or hydrated lime) than limestone-based FGD systems 

(more dollars per mole of calcium), and the reagent must be stored in a steel or concrete silo. Limestone can be 

stored outdoors in a pile and moisture is not a problem in its reactivity. The wet FGD system consumes 5.9 tph of 

reagent per unit, while the dry FGD system consumes 4.2 tph of reagent per unit. 

Reagent utilization for a dry FGD system is poorer compared to a wet limestone system meaning the reagent SR for 

a dry FGD system is higher than the SR for a wet limestone FGD system (on the same basis) to achieve comparable 

SO2 removal (more moles of calcium per mole of sulfur dioxide). The cost of reagent is provided for in the O&M 

costs presented herein. 

3.4.3 Waste Byproducts 

For dry FGD systems, the resulting byproducts are in dry form and can be handled with conventional pneumatic fly 

ash handling equipment. The dry FGD waste containing CaSO3 • 0.5H2O, CaSO4 • 2H2O, Ca(OH)2, and fly ash is 

land-filled similarly to waste containing just fly ash. This material is stable in the landfill and could be fixated with 

fly ash to make it less permeable. Wet FGD waste is 99% CaSO4. 2H2O, which would be land-filled. Again, the wet 

FGD waste can be fixated with fly ash and addition of lime to make it less permeable. Currently, most utilities can 

dispose both of these wastes in a lined landfill. 

Additionally, there is no liquid waste from a dry FGD system, whereas wet FGD systems typically produce a liquid 

waste stream, depending on the disposition of the byproduct. In the case of the White Bluff Station, a wastewater 

treatment plant may be required to treat the liquid waste prior to discharge due to the high chloride level of the 

makeup water from cooling tower blowdown. The wastewater treatment plant produces a small volume of solid 

waste, rich in heavy metals (including oxidized mercury) that can be disposed of in a typical landfill. A dry FGD 

system can provide an outlet for process wastewater from other parts of the power plant. Since the dry FGD system 

evaporates all its water, heavy metals, including oxidized mercury, are present in the FGD byproduct. The 

byproducts tend to trap the trace metals and the concentrations are low enough to qualify the byproducts for typical 

landfills. 
3-12

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.5 SULFUR REDUCTION TECHNOLOGY COST EVALUATION 

3.5.1 Capital Cost 

S&L’s capital cost estimates for a retrofit dry FGD and a retrofit wet FGD system for White Bluff Units 1 and 2 

encompass the equipment, material, labor, and all other required direct costs. The underlying assumption is that the 

project will be implemented on a multiple contracting basis. The capital costs are based on burning 100% PRB 

coal. The capital cost estimates provided herein are “total plant cost,” and include the following: 

• Equipment and material 

• Installation labor 

• Indirect field costs and BOP engineering 

• Contingency (20%) 

• Erection contractor profit (at 10% of material and labor) 

• General and administration (at 5% of material and labor) 

• Freight 

• Allowance for funds used during construction (AFUDC [8.24%]) 

• Sales/use tax (not included) 

• Startup and commissioning 

• Spare parts (1% of equipment) 

License fees and royalties are not expected for the proposed control strategies. The capital costs are summarized in 

Appendixes C and D for dry and wet FGD, respectively. 

The capital cost estimates for installing dry FGD or wet FGD at White Bluff Units 1 and 2 include the following: 

3.5.1.1 Reagent Handling and Preparation System 

3.5.1.1.1 Wet FGD 

• Limestone delivered by truck 

• Long-term limestone storage for 30 days 

• Ball mills provided to grind the limestone 
3-13

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

• Slurry storage tank with 24 hours of capacity 

• Slurry feed pumps for each absorber 

• Slurry pipe loops for the Units 1 and 2 absorbers 

3.5.1.1.2 Dry FGD 

• Lime delivered by truck 

• Silos for long term storage, 14 days 

• Ball mill slakers 

• Slurry storage tank with 24 hours of capacity 

• Feed slurry pumps 

3.5.1.2 Absorber Systems 

3.5.1.2.1 Wet FGD 

• 1 x 100% absorber for each unit 

• Spray headers along with one slurry recycle pump for each header 

• Oxidation air compressors for each unit 

• 2205 alloy absorber, wet/dry interface – solid C-276, and outlet duct C-276 clad 

3.5.1.2.2 Dry FGD 

• 3 x 33.3% absorbers for Unit 1 and 3 x 33.3% absorbers for Unit 2 

• Pulse-jet baghouse, 3.5:1 air-to-cloth ratio, one for each absorber 

3.5.1.3 Flue Gas Systems 

3.5.1.3.1 Wet FGD 

• Inlet (carbon steel) and outlet (C-276-lined) ducts for each absorber 

• Bypass dampers 

• 2 x 50% booster induced draft (ID) fans for each unit 

• Wet chimney with FRP liner for each unit 
3-14

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.5.1.3.2 Dry FGD 

• Inlet and outlet ducts (carbon steel) 

• 2 x 50% booster induced draft (ID) fans for each unit 

3.5.1.4 Byproduct/Waste Handling 

3.5.1.4.1 Wet FGD 

• Hydroclone separator for each unit 

• Slurry pipeline from each absorber 

• Rotary drum vacuum filters 

• Stackout conveyors 

• Wastewater treatment - minimal 

3.5.1.4.2 Dry FGD 

• Waste recycle system 

• Waste conveying system 

• Silos with 3 days of waste storage capacity 

• Dustless unloaders 

3.5.1.5 Electrical/Instrumentation 

3.5.1.5.1 Wet/Dry FGD 

• Transformers 

• Switchgear 

• Instrumentation 

3.5.1.6 Makeup Water Supply/Wastewater Treatment 

3.5.1.6.1 Wet/Dry FGD 

• Makeup water treatment facility 

• Water storage tank 
3-15

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.5.1.7 Balance-of-Plant 

3.5.1.7.1 Wet/Dry FGD 

• Compressor for instrument air, service air 

• Foundations, steel, demolition, relocations, new storage warehouse, etc. 

• Roads, storm drainage, etc. 

3.5.2 Fixed and Variable Operating Costs 

The fixed O&M costs determined for this study consist of operating labor, maintenance labor, maintenance 

material, and administrative labor. The wet FGD will require an estimated 21 additional full-time operators and 

maintenance personnel and the dry FGD will require an estimated 16 additional full-time operators and 

maintenance personnel for each shift for both units. 

The operators would be looking after the absorber system, reagent preparation, and byproduct/waste system. The 

limestone receiving/handling will also require an operator. The existing shift supervisors will handle added 

responsibility for the FGD system. Due to existing work load on the plant chemist, an additional lab technician will 

be added for the FGD system. 

S&L’s estimated staffing levels for White Bluff are as shown in Table 3-3. 

Table 3-3. FGD System Labor Requirements 

Staff Dry FGD Wet FGD 

Reagent unloading 2 2 

Absorber 10 10 

Dewatering/reagent preparation 0 5 

Gypsum handling 0 2 

Recycle/fly ash handling 3 0 

Laboratory technician 0 1 

System engineer 1 1 

Total Staffing 16 21 
3-16

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Annual maintenance material and labor costs shown herein have been estimated based on technology operating 

experience in the U.S. The annual maintenance cost includes maintenance material for various subsystems and the 

labor required to perform the maintenance. The annual maintenance material and labor is 0.07% and 0.065% of the 

initial equipment cost in the capital cost estimate for wet and dry FGD respectively. 

Variable O&M costs determined for each application include the cost of consumables, including reagent (lime or 

limestone), byproduct management, water, and power requirements. These costs have been calculated based on the 

capacity factors provided by Entergy. 

The O&M cost basis with 0.8 lb SO2/mmBtu as operating sulfur is shown in Table 3-4: 

Table 3-4. O&M Cost Basis (both units combined) 

Parameter Wet FGD Dry FGD Cost ($) 

Limestone, t/h 11.7 0 38.00 $/ton 

Lime, t/h 0 8.4 107.00 $/ton 

Waste disposal, t/h 22.6 17.8 8.58 $/ton 

Auxiliary power, MWH 28.0 22.8 47.00 $/MWH 

Water, gpm 2,522 2,100 0.92 $/1000 gal 

Bag replacement 0 Every 3 years 110 per bag 

The following basis was used to calculate net present value (NPV): 

• Evaluation period - 40 years 

• Discount rate - 8.24% 

• Capital cost escalation rate - 3.0% 

• O&M cost escalation rate - 2.0% 

The variable cost for the wet FGD assumes that any generated gypsum is land-filled and will not be saleable. 

However, gypsum is potentially saleable. The variable cost for the dry FGD assumes that all generated solid waste 

will be land-filled. 
3-17

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Also note that for the wet LSFO FGD and dry FGD, reagent cost and byproduct management cost are at 95% SO2

removal. Wet FGD is capable of 98% SO2 removal, but the system comparison is based on 95% as the compliance 

with SIP requires the emission limit of 0.15 lb SO2/mmBtu. 

Auxiliary power costs developed reflect the additional power requirements associated with operation of the new 

booster ID fans as well as the estimated power consumption for the absorber, reagent preparation, and byproduct 

handling areas. 

3.5.3 Preliminary Cost Summary 

Based on the economic parameters – the total capital cost, fixed O&M cost, and variable O&M cost – a financial 

model was developed to calculate the NPV and levelized annualized cost to determine a low-cost solution. The 

model input and results for the base case are presented in Appendix E, which summarizes a comparison of wet and 

dry FGD installation costs for two units. 

Table 3-5. Summary Comparison of Wet and Dry FGD Levelized Costs (yr. 2013) for White Bluff Units 1 & 2 

Cost Parameter 

Wet FGD - 

Limestone 

Dry FGD With 

Baghouse 

Capital cost, M$ ($/kW) 744.8 (441) 706.9 (419) 

Fixed O&M cost, M$/yr ($/kW-yr) 8.4 (4.95) 7.1 (4.22) 

Variable O&M cost, M$/yr ($/MWh) 17.4 (1.58) 19.9 (1.81) 

Total O&M cost, M$/yr 25.8 27.0 

NPV, M$ 1,484 1,449 

Differential, M$ 35 0 

Annualized cost, M$/yr 113.8 111.1 

Differential, M$/yr 2.7 0 

Note: Discount rate of 7.67% was used for the levelized cost. 

Based on the NPV analysis, it can be concluded that dry FGD is the low-cost solution, with less than 1.0% 

difference between wet and dry FGD. 
3-18

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

3.5.4 Sensitivity Analyses 

Sensitivity analyses were performed with the following key parameters: 

• Evaluate impact of burning higher-sulfur fuels - 3 lb SO2/mmBtu and 5 lbs SO2/mmBtu. 

• Evaluate impact of low-cost reagent delivery by train. 

• Evaluate impact of two-absorber module design for dry FGD. 

• Evaluate impact of mercury control with ACI for future Hg-MACT. 

• Impact of SCR - related to sulfuric acid control. 

3.5.4.1 Evaluate Impact of Burning Higher-Sulfur Fuels – 3 lb SO2/mmBtu and 5 lb SO2/mmBtu 

The economic analysis was performed with a variation in the fuel levels of SO2 subjected to scrubbing. Figure 3-1 

summarizes the impact due to the changes in SO2 operating levels. 
3-19

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 3-1. Impact of SO2 in Fuel on Levelized Cost 

107.08

113.78

120.47

160.85

108.42

111.06

113.71

100

110

120

130

140

150

160

170

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

The base case comparison for 2 lb SO2/mmBtu (operation at 0.8 lb SO2/mmBtu) indicates that the dry FGD would 

cost approximately 1.0% lower cost than wet FGD. The main difference is due to the cost differential between lime 

and limestone. The annual differential in O&M cost due to reagent cost of more than $3.4 million negates the 

higher capital cost for wet FGD. The differential is higher at 3 lb/mmBtu coal predominantly due to somewhat 

higher cost associated with capital for wet FGD system. Again, the O&M cost was based on 0.8 lb SO2/mmBtu. 

3.5.4.2 Evaluate Impact of Low-Cost Reagent Delivery by Train 

The delivery of reagent by train results in savings of almost $10/ton in transportation cost. It is assumed that the 

infrastructure to deliver the lime or limestone may cost an additional $10 million in capital expenditure. At this 

cost, the differential between dry FGD and wet FGD remains the same as the base case. It appears that if the capital 
3-20

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

cost of rail delivery is lower than $10 million, the reagent cost saving due to lower-per-unit cost could be justified 

with rail delivery. The results are shown in Figure 3-2. 

Figure 3-2. Impact of Rail Delivery on Levelized Cost 

107.22

113.96

120.70

155.60

108.82

111.49

114.17

100

110

120

130

140

150

160

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

3.5.4.3 Evaluate Impact of Two-Absorber Module Design for Dry FGD 

The dry FGD system is based on the use of three absorber modules. Alstom had proposed two modules on units 

with a similar gas flow in the past. However, B&W and Siemens had utilized three modules. The use of two 

modules will save a significant amount of ductwork, foundations, and structural steel cost. The sensitivity analysis 

performed with the use of the two-module scenario resulted in approximately 7% savings in capital cost, as shown 

in Figure 3-3. 
3-21

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 3-3. Impact of Two Dry FGD Absorber Modules on Levelized Cost 

107.08

113.78

120.47

160.85

103.21

105.72

108.22

100

110

120

130

140

150

160

170

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

By lowering the capital cost for dry FGD by 7%, the annualized cost differential reduces to 2% from 6.5% still 

favoring wet FGD. However, if the sulfur level drops to approximately 1.5 lb SO2/mmBtu, the dry FGD becomes 

cost-competitive. 

3.5.4.4 Evaluate Impact of Mercury Control with ACI for Future Hg-MACT 

The base dry and wet FGD system design is based on the use of high-sulfur PRB coal. The PRB coals generate 

greater than 80% elemental mercury, which is difficult to control with wet or dry FGD. It is indeed possible that the 

Hg-MACT may require 90% mercury removal. The dry FGD will require ACI to achieve the desirable target. For 

wet FGD, the use of ACI either ahead of the existing ESP or ahead of a new compact baghouse (compact hybrid 

particulate collector [COHPAC]) may be required. For 5 lb SO2/mmBtu fuel, it is assumed that there is enough 

chloride in the fuel to achieve an overall 90% mercury removal efficiency. If it is assumed that 90% can be 
3-22

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

achieved (similar to regulations in Illinois), by ACI ahead of the ESP for wet FGD, the sensitivity is as presented in 

Figure 3-4. 

Figure 3-4. Impact of Mercury Control with ACI for Future Hg-MACT on Levelized Cost 

126.59

135.15

141.84

160.85

115.12

118.76

121.40

100

110

120

130

140

150

160

170

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

Dry FGD - ACI at Absorber Inlet (1.5 lb/mmACF)

Wet FGD - ACI at ESP Inlet (5 lb/mmACF)

5 lb/mmBtu do not require ACI

ACI ahead of the ESP raises the evaluated cost significantly for the wet FGD system, rendering dry FGD a low-cost 

solution below 2 and 3 lb SO2/mmBtu fuel (operating at 0.8 lb/mmBtu PRB coal). However, if ACI has a major 

impact on ESP performance, a COHPAV may be required. The sensitivity of adding COHPAC to wet FGD is 

shown in Figure 3-5. 
3-23

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

Figure 3-5. Impact of Mercury Control with ACI Ahead of 

COHPAC Baghouse for Wet FGD to Meet Future Hg-MACT 

136.82

142.83

149.52

160.85

115.12

118.76

121.40

100

110

120

130

140

150

160

170

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

Dry FGD - ACI at Absorber Inlet (1.5 lb/mmACF)

Wet FGD - ACI at COHPAC Inlet (1.5 lb/mmACF)

5 lb/mmBtu do not require ACI

The differential between dry and wet FGD increases significantly if wet FGD requires the additional baghouse, 

rendering dry FGD even more economical. 

3.5.4.5 Evaluate Impact of SCR - Related to Sulfuric Acid Control 

The base dry and wet FGD system designs are based on the use of high-sulfur PRB coal. The dry system will have 

an advantage over the wet system if the condensable emissions are further lowered from the existing level of 

265 lb/hr (718 lb/hr total – 453 lb/hr filterable) or 0.03 lb/mmBtu. If all of the condensable emission is assumed to 

be sulfuric acid, it will be equal to approximately 10 ppmvd (@3% O2). With the installation of either wet or dry 

FGD for 2 lb SO2/mmBtu fuel, the sulfuric acid emission will be lower than the current allowable limit. However, a 

wet FGD system designed for 2, 3 and 5 lb SO2/mmBtu will require an additional alkali injection system, whereas a 
3-24

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

dry FGD system installed on 3 lb/mmBtu fuel will not require any additional alkali injection. It is assumed that if 

SO3 control is required, the emissions will have to be lowered to similar levels as dry FGD, which could be lower 

than 5 ppmvd (@3%O2). The Trona requirement was estimated to achieve this level without any credit for SO3

capture by the wet FGD. 

The injection of Trona required to control SO3 eliminates the cost advantage of wet FGD over dry FGD up to 3 lb 

SO2/mmBtu fuel. The results can be seen in Figure 3-6. 

Figure 3-6. Impact of SO3 Control with Trona Injection for 

Future SCR Resulting in Increased Sulfuric Acid Emission 

108.38

116.12

122.85

175.11

108.42

111.06

113.71

100

110

120

130

140

150

160

170

180

0123456

SO2, lb/mmBtu

Levelized Cost, M$/yr

Wet FGD

Dry FGD

Des. SO2 lb/mmBtu 2.0 3.0 5.0 

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

2, 3, and 5 lb sulfur wet FGD will require SO3 control 

with trona injection if fired with Bitumonous coal

3.6 SULFUR REDUCTION TECHNOLOGY CONCLUSIONS 

The economic evaluation showed that a dry FGD system is cost-effective when the design sulfur in the coal is 

below 3 lb SO2/mmBtu and the unit is operated at or below 0.8 lb SO2/mmBtu, regardless of the possible 
3-25

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

sensitivities associated with reagent cost, PM 2.5, or mercury regulations. Dry FGD is the low-cost technology 

through most of the sensitivities. Dry FGD becomes even more attractive below 3 lb/mmBtu fuel under the 

following scenarios: 

1. The capital cost can be reduced by 7% with the use of two modules in lieu of the three modules anticipated 

in the base case design. 

2. The Hg-MACT regulation requiring 90% reduction while burning PRB coal would give dry FGD a cost 

advantage. 

3. If the operating sulfur is lower than 1.2 lb/mmBtu, the dry FGD becomes cost-competitive with wet FGD 

due to reduced operating cost for lime as a reagent.

SCR system and particulate emissions systems installations have no significant impact on the selection of 

technology as long as current permit limits are maintained. The dry FGD system will have an advantage over the 

wet FGD system if the condensable emission rate is further lowered from the existing level of 265 lb/hr (718 lb/hr 

total – 453 lb/hr filterable) or 0.03 lb/mmBtu. If all the emission is assumed to be sulfuric acid, it will be equal to 

approximately 10 ppmvd (@ 3% O2). With the installation of either FGD for 2 lb SO2/mmBtu fuel, the sulfuric acid 

emission rate will be lower than the current allowable limit. The wet FGD system designed for bituminous coal 

with 2, 3 and 5 lb/mmBtu will require an additional alkali injection system, whereas the dry FGD system installed 

on 2 and 3 lb/mmBtu fuel will not require any additional alkali injection. The impact of future SO3 control almost 

eliminates the cost advantage of wet FGD. 

The wet FGD system will have an advantage over dry FGD in the case of CO2 emission control as it is capable of 

lowering the SO2 concentration slightly better than the dry FGD. However, both systems will require some sort of 

pre-scrubbing, which will result in somewhat higher operating cost for the CO2 scrubbing installed on the dry FGD. 
WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

APPENDIX A 

Dry FGD General Arrangement 


WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 2A Issued 

10-9-08 

Project 12303-004 

APPENDIX B 

Wet FGD General Arrangement 

WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

APPENDIX C 

Dry FGD Capital Cost Estimate 



WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

APPENDIX D 

Wet FGD Capital Cost Estimate 



WHITE BLUFF STATION UNITS 1 AND 2 SL-009510

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued 

10-28-08 

Project 12303-004 

APPENDIX E 

Financial Analysis Summary 
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Economic Parameter Inputs

Input Assumptions Source Case Technology Tax Fuel Ty

Case Number Selection: 5 1 Case 1 - Wet FGD 7-Year Amort. PRB Coal 

Technology Case 5 - Wet FGD 2 Case 2 - Dry FGD 7-Year Amort. PRB Coal 

Tax Depreciation 7-Year Amort. 3 Case 3 - Wet FGD 7-Year Amort. PRB Coal Fuel Type PRB Coal 4 Case 4 - Dry FGD 7-Year Amort. PRB Coal 

5 Case 5 - Wet FGD 7-Year Amort. PRB Coal 

Basis for Fixed Charges Regulated

Evaluation Period (years) 40 Econ Parameters. 5-12-08

Book Life - Regulated (years) 40 Econ Parameters. 5-12-08

lb/mmBtu M$/yr M$/yr

Base Year for Expressing Costs 2008 Econ Parameters. 5-12-08 wet dryCommercial Operating Date 2013 Econ Parameters. 5-12-08

Compliance Date 9/27/2013 Econ Parameters. 5-12-08

1 107.08 108.42

Escalation Rates 2 113.78 111.06

Capital Costs (%/year) 3.00% Email 5-15-08 3 120.47 113.71O&M Costs (%/year) 2.00% Econ Parameters. 5-12-08 5 160.85Property Taxes (%/year) * 3.00% Email 5-15-08

Property Tax Rate 0.944% Econ Parameters. 5-12-08

Insurance Rate 0.000% Included in Property Tax

Tax Rate for Deferred Taxes 37.275%Common Equity Fraction 0.5359 Econ Parameters. 5-12-08

Preferred Stock Fraction 0.0444 Econ Parameters. 5-12-08Debt Fraction 0.4197 Econ Parameters. 5-12-08Return on Common Equity 9.90%

Return on Preferred Stock 5.99%Return on Debt 6.34%

* Property Taxes are applied to market value

Federal and State tax rate, % 39.23% Econ Parameters. 5-12-08

Before tax cost of money 8.23%

After tax cost of money 7.19%Weighted Annuity Factor 7.67%

Total Capital Requirement 819,294,000Fixed Charge Rate Parameters

Investment Book Depreciation 20,482,350ITC Normalized -Preferred AFUDC Recovery -

Equity AFUDC Recovery -Debt Book Depreciation 8,596,442Preferred Book Depreciation 909,416Equity Book Depreciation 10,976,491

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Case 1 - Wet FGD Case 2 - Dry FGD Case 3 - Wet FGD Case 4 - Dry FGD Case 5 - Wet 

2 lb/mmBtu 2 lb/mmBtu 3 lb/mmBtu 3 lb/mmBtu 5 lb/mmBtu

1 2 3 45

Input Assumptions

Net Plant Capacity (MW) 1,688 1,688 1,688 1,688 1,688

Capacity Factor (at In-Service Date) 72.00% 72.00% 72.00% 72.00% 72.00% CF's tab. Email. (used only for long term average in yea

Equivalent Availability Factor 90.00% 90.00% 90.00% 90.00% 90.00%Aux Power (MW) 28.00 22.80 32.60 23.60 40.40Aux Power (MWh/year at full load) 245,280 199,728 285,576 206,736 353,904 Email 5-15-08

Construction Duration (months) 48.0 48.0 48.0 48.0 48.0 Placeholder

Tie-In Outage Duration (months) 3.0 3.0 3.0 3.0 3.0 Placeholder

 Amount in Excess of Normal Outage (mo 1.5 1.5 1.5 1.5 1.5 PlaceholderBase Year 2008 2008 2008 2008 2008

In-Service Year 2013 2013 2013 2013 2013Total Water Consumption (gpm) 2,522 2,100 2,562 2,120 2,640 Email 5-15-08

Waste Disposal (lb/hr) 45,138 35,652 45,138 35,652 289,070 Email 5-15-08 22.569

Lime Rate (tons/hr) 0.0 8.4 0.0 8.4 0.0 Email 5-15-08

Limestone Rate (tons/hr) 11.7 0.0 11.7 0.0 74.1 Email 5-15-08

Capital Investment Costs 

Direct & Indirect Costs 483,486,000 458,871,000 504,276,000 470,802,000 531,835,000 Email 5-16-08

Escalation 49,599,000 47,059,000 51,732,000 48,283,000 54,559,000 Email 5-16-08Contingency 106,617,000 101,186,000 111,202,000 103,817,000 117,279,000 Email 5-16-08Taxes 0 0 0 00 Email 5-16-08

AFUDC 105,110,000 99,781,000 109,630,000 102,375,000 115,621,000 Email 5-16-08

Total Base-Year Value 744,812,000 706,897,000 776,840,000 725,277,000 819,294,000

Value at In-Service Date 744,812,000 706,897,000 776,840,000 725,277,000 819,294,000$/kW 441 419 460 430 485

Fixed O&M (2008 $/year)

Operating Labor 1,773,000 1,351,000 1,773,000 1,351,000 1,773,000 Email 5-15-08

Materials and Supplies 3,384,000 2,983,000 3,530,000 3,060,000 3,723,000 Email 5-15-08Maintenance Labor 2,256,000 1,989,000 2,353,000 2,040,000 2,482,000 Email 5-15-08

Administrative Labor 0 0 0 00

Other 0 0 0 00Total Base-Year Value 7,413,000 6,323,000 7,656,000 6,451,000 7,978,000

$/kW-year 4.39 3.75 4.54 3.82 4.73

Variable O&M (2008 $)

Bag Replacement Cost 0 1,653,000 0 1,653,000 0

Lime, $/ton $107.00 $107.00 $107.00 $107.00 $107.00 Email 5-15-08

Limestone, $/ton $38.00 $38.00 $38.00 $38.00 $38.00 Email 5-15-08

Total Water Requirement, $/1000 gal $0.66 $0.66 $0.66 $0.66 $0.66 Email 5-15-08

Bag Cost, $/bag $110.00 $110.00 $110.00 $110.00 $110.00 Waste Ash Disposal, $/ton $8.58 $8.58 $8.58 $8.58 $8.58 Email 5-15-08

Technology Base Year Cost and Performance Inputs

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB Coal

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operating Year 1 2 3 4 5 6 7 8 9 10 11 

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fuel Prices ($/mmBtu)

PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 

Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1Variable O&M Calculations

Consumption Rates

Lime (tons) 00000000000

Limestone (tons) 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 70,848 76,183 75,379 7

Total Water Requirement (1000s ga 986,988 976,576 1,017,281 1,018,738 952,938 955,961 853,928 882,096 917,876 986,988 976,576 1,01

Waste Ash Disposal (tons) 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 136,900 147,208 145,655 15

Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 1Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 Bag Cost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 1

Total Water Requirement, $/1000 gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 

Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0 Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1Capacity Factor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76

Annual Generation (MWh) 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347Aux. Power (MWh) 182,631 180,704 188,236 188,506 176,330 176,889 158,009 163,222 169,842 182,631 180,704 18Aux. Power Cost ($/MWh) 66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 1

Fuel Price ($/mmBtu) 2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3

Fuel Consumption (mmBtu/year) 00000000000

Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis 113,758,949 108,569,447 102,748,573 96,935,254 91,129,718 85,332,198 79,542,935 75,469,428 73,750,163 72,678,449 71,616,029 70,563

Fixed O&M 8,348,242 8,515,207 8,685,511 8,859,221 9,036,406 9,217,134 9,401,476 9,589,506 9,781,296 9,976,922 10,176,460 10,379Fuel 00000000000Aux Power Purchase 12,053,370 11,731,254 12,161,351 12,718,126 12,133,421 13,455,728 13,287,300 15,173,294 16,305,449 18,106,946 18,502,241 19,904

Bag Replacement 00000000000Lime 00000000000Limestone 3,196,265 3,225,800 3,427,458 3,501,015 3,340,382 3,417,998 3,114,248 3,281,316 3,482,703 3,819,833 3,855,129 4,09Total Water Requirement 726,291 734,798 782,647 801,403 766,507 786,240 718,124 758,504 807,029 887,320 897,714 95Waste Ash Disposal 1,393,942 1,406,823 1,494,769 1,526,848 1,456,794 1,490,643 1,358,173 1,431,034 1,518,862 1,665,890 1,681,283 1,78

Total Revenue Requirements 139,477,059 134,183,329 129,300,310 124,341,867 117,863,228 113,699,941 107,422,257 105,703,082 105,645,503 107,135,360 106,728,857 107,686

Busbar Electricity Price ($/MWh) 12.67 12.32 11.39 10.94 11.09 10.66 11.28 10.74 10.32 9.73 9.80 

Levelized ($/MWh) 10.64

Present Value (PVRR) 130,123,123 116,789,005 104,991,625 94,194,203 83,298,431 74,967,052 66,077,889 60,659,836 56,560,898 53,511,831 49,733,673 46,814

Cumulative PVRR 130,123,123 246,912,128 351,903,754 446,097,957 529,396,388 604,363,440 670,441,329 731,101,165 787,662,063 841,173,894 890,907,568 937,72Net Present Value = 1,484,233,596

Levelized ($/year) 113,775,915

4.95 $/kW-yr fixed

1.58 $/MWH variable

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.64

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,484,233,596

Levelized ($/year) 113,775,915

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 

16 17 18 19 20 21 22 23 24 25 26 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 

1.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1

00000000000

65,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 7

853,928 882,096 917,876 986,988 976,576 1,017,281 1,018,738 952,938 955,961 853,928 882,096 95127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 14

166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 2

56.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 

163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 2

1.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 

12.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.00.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7

1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1

64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72

9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646

158,009 163,222 169,842 182,631 180,704 188,236 188,506 176,330 176,889 158,009 163,222 17

116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 13.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4

00000000000

0.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

66,453,371 65,452,863 64,463,784 63,486,476 62,521,294 61,568,600 60,628,770 59,702,188 58,789,254 57,890,376 57,005,975 56,136

11,235,635 11,460,347 11,689,554 11,923,345 12,161,812 12,405,048 12,653,149 12,906,212 13,164,337 13,427,623 13,696,176 13,970

00000000000

18,445,845 19,483,034 20,729,466 22,791,829 23,058,813 24,560,366 25,148,946 24,053,878 24,673,113 22,535,563 23,802,712 26,333

0000000000000000000000

3,721,814 3,921,476 4,162,152 4,565,054 4,607,236 4,895,254 5,000,311 4,770,888 4,881,743 4,447,913 4,686,527 5,172

877,343 926,675 985,960 1,084,052 1,096,751 1,168,169 1,196,164 1,144,079 1,173,532 1,071,863 1,132,133 1,252

1,623,143 1,710,218 1,815,181 1,990,893 2,009,289 2,134,898 2,180,716 2,080,660 2,129,006 1,939,806 2,043,869 2,255

102,357,151 102,954,614 103,846,097 105,841,649 105,455,195 106,732,336 106,808,056 104,657,906 104,810,984 101,313,144 102,367,392 105,120

10.75 10.46 10.14 9.61 9.68 9.41 9.40 9.85 9.83 10.64 10.40 

33,708,960 31,631,857 29,766,018 28,303,416 26,308,855 24,841,721 23,192,169 21,201,232 19,808,316 17,863,158 16,838,593 16,13

1,092,319,570 1,123,951,426 1,153,717,445 1,182,020,861 1,208,329,716 1,233,171,437 1,256,363,606 1,277,564,838 1,297,373,154 1,315,236,312 1,332,074,905 1,348,206

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.64

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,484,233,596

Levelized ($/year) 113,775,915

2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

31 32 33 34 35 36 37 38 39 40

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.67

2.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.6554

0000000000

73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668

954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348

232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.12

76.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82

219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.91

1.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.75

17.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.50

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%

2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.4379

72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%

10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554

176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602

162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.6742

0000000000

0.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.0622

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

52,816,807 52,028,864 51,258,728 50,506,931 49,774,025 49,060,576 48,367,167 47,694,401 47,042,895 46,413,28915,121,685 15,424,119 15,732,601 16,047,253 16,368,198 16,695,562 17,029,473 17,370,063 17,717,464 18,071,813

0000000000

28,784,593 29,432,246 30,094,472 30,771,597 31,463,958 32,171,897 32,895,765 33,635,920 34,392,728 35,166,564

00000000000000000000

5,598,466 5,710,435 5,824,644 5,941,137 6,059,960 6,181,159 6,304,782 6,430,878 6,559,495 6,690,6851,369,087 1,399,891 1,431,389 1,463,595 1,496,526 1,530,198 1,564,627 1,599,832 1,635,828 1,672,6342,441,580 2,490,412 2,540,220 2,591,025 2,642,845 2,695,702 2,749,616 2,804,608 2,860,700 2,917,914

106,132,218 106,485,968 106,882,054 107,321,538 107,805,512 108,335,094 108,911,431 109,535,701 110,209,111 110,932,900

9.97 10.00 10.04 10.08 10.13 10.18 10.23 10.29 10.35 10.42

12,338,145 11,549,062 10,814,609 10,130,821 9,494,026 8,900,826 8,348,074 7,832,857 7,352,478 6,904,437

1,402,906,405 1,414,455,468 1,425,270,077 1,435,400,897 1,444,894,923 1,453,795,749 1,462,143,823 1,469,976,680 1,477,329,158 1,484,233,596

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB Coal

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operating Year 1 2 3 4 5 6 7 8 9 10 11 

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fuel Prices ($/mmBtu)

PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 

Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1Variable O&M Calculations

Consumption Rates

Lime (tons) 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 51,007 54,848 54,269 5

Limestone (tons) 00000000000

Total Water Requirement (1000s ga 821,838 813,168 847,062 848,275 793,485 796,002 711,042 734,497 764,290 821,838 813,168 84

Waste Ash Disposal (tons) 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 108,129 116,270 115,044 11

Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 1Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 Bag Cost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 1

Total Water Requirement, $/1000 gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 

Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0 Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1Capacity Factor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76

Annual Generation (MWh) 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347Aux. Power (MWh) 148,713 147,145 153,278 153,497 143,583 144,038 128,665 132,909 138,300 148,713 147,145 15Aux. Power Cost ($/MWh) 66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 1

Fuel Price ($/mmBtu) 2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3

Fuel Consumption (mmBtu/year) 00000000000

Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis 107,967,997 103,042,669 97,518,109 92,000,720 86,490,718 80,988,323 75,493,765 71,627,622 69,995,877 68,978,719 67,970,381 66,97

Fixed O&M 7,120,725 7,263,139 7,408,402 7,556,570 7,707,702 7,861,856 8,019,093 8,179,475 8,343,064 8,509,926 8,680,124 8,853Fuel 00000000000Aux Power Purchase 9,814,887 9,552,593 9,902,815 10,356,188 9,880,071 10,956,807 10,819,659 12,355,396 13,277,294 14,744,227 15,066,111 16,20

Bag Replacement 1,861,546 1,878,748 1,996,196 2,039,037 1,945,482 1,990,687 1,813,779 1,911,081 2,028,372 2,224,720 2,245,278 2,385Lime 6,543,322 6,619,971 7,051,053 7,220,029 6,905,645 7,083,421 6,469,751 6,833,537 7,270,715 7,994,074 8,087,716 8,614Limestone 00000000000Total Water Requirement 604,762 611,846 651,689 667,306 638,250 654,681 597,962 631,585 671,991 738,847 747,502 79Waste Ash Disposal 1,100,988 1,111,161 1,180,625 1,205,962 1,150,630 1,177,366 1,072,736 1,130,284 1,199,654 1,315,782 1,327,941 1,41

Total Revenue Requirements 135,014,228 130,080,128 125,708,889 121,045,812 114,718,497 110,713,140 104,286,744 102,668,981 102,786,967 104,506,296 104,125,053 105,239

Busbar Electricity Price ($/MWh) 12.26 11.94 11.08 10.65 10.79 10.38 10.95 10.43 10.04 9.49 9.56 

Levelized ($/MWh) 10.39

Present Value (PVRR) 125,959,589 113,217,706 102,075,398 91,697,303 81,075,930 72,997,731 64,149,163 58,918,657 55,030,484 52,198,670 48,520,349 45,750

Cumulative PVRR 125,959,589 239,177,295 341,252,693 432,949,995 514,025,926 587,023,656 651,172,819 710,091,476 765,121,960 817,320,630 865,840,979 911,59Net Present Value = 1,448,851,893

Levelized ($/year) 111,063,683

4.22 $/kW-yr fixed

1.81 $/MWH variable

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.39

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,448,851,893

Levelized ($/year) 111,063,683

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 

16 17 18 19 20 21 22 23 24 25 26 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 

1.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 147,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 5

00000000000

711,042 734,497 764,290 821,838 813,168 847,062 848,275 793,485 796,002 711,042 734,497 79100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 11

166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 2

56.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 

163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 2

1.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 

12.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.00.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7

1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1

64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72

9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646

128,665 132,909 138,300 148,713 147,145 153,278 153,497 143,583 144,038 128,665 132,909 14

116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 13.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4

00000000000

0.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

63,070,531 62,120,955 61,182,225 60,254,668 59,338,618 58,434,422 57,542,434 56,663,021 55,796,560 54,943,439 54,104,060 53,278

9,583,558 9,775,229 9,970,734 10,170,149 10,373,552 10,581,023 10,792,643 11,008,496 11,228,666 11,453,239 11,682,304 11,915

00000000000

15,020,188 15,864,756 16,879,708 18,559,061 18,776,462 19,999,155 20,478,427 19,586,729 20,090,963 18,350,387 19,382,208 21,442

2,167,633 2,283,919 2,424,092 2,658,747 2,683,315 2,851,060 2,912,247 2,778,627 2,843,191 2,590,522 2,729,495 3,0127,904,190 8,348,634 8,882,740 9,766,479 9,880,883 10,524,311 10,776,522 10,307,276 10,572,624 9,656,667 10,199,650 11,284

00000000000

730,540 771,617 820,981 902,660 913,234 972,702 996,013 952,643 977,168 892,511 942,696 1,042

1,282,019 1,350,794 1,433,698 1,572,482 1,587,012 1,686,223 1,722,411 1,643,383 1,681,569 1,532,131 1,614,324 1,78

99,758,660 100,515,905 101,594,178 103,884,245 103,553,076 105,048,896 105,220,697 102,940,176 103,190,740 99,418,897 100,654,737 103,758

10.47 10.22 9.92 9.44 9.51 9.26 9.26 9.68 9.68 10.44 10.23 

32,853,208 30,882,586 29,120,538 27,779,981 25,834,316 24,449,904 22,847,492 20,853,260 19,502,105 17,529,172 16,556,875 15,922

1,062,579,458 1,093,462,043 1,122,582,581 1,150,362,562 1,176,196,878 1,200,646,782 1,223,494,274 1,244,347,534 1,263,849,639 1,281,378,810 1,297,935,685 1,313,858

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.39

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,448,851,893

Levelized ($/year) 111,063,683

2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

31 32 33 34 35 36 37 38 39 40

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.67

2.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.655453,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037

0000000000

794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432

232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.12

76.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82

219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.91

1.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.75

17.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.50

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%

2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.4379

72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%

10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554

143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804

162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.6742

0000000000

0.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.0622

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

50,128,143 49,380,311 48,649,378 47,935,852 47,240,255 46,563,125 45,905,014 45,266,495 44,648,155 44,050,59912,898,208 13,156,172 13,419,295 13,687,681 13,961,435 14,240,663 14,525,477 14,815,986 15,112,306 15,414,552

0000000000

23,438,883 23,966,257 24,505,498 25,056,872 25,620,652 26,197,116 26,786,551 27,389,249 28,005,507 28,635,631

3,260,620 3,325,832 3,392,349 3,460,196 3,529,400 3,599,988 3,671,987 3,745,427 3,820,336 3,896,742

12,334,425 12,611,950 12,895,719 13,185,872 13,482,555 13,785,912 14,096,095 14,413,257 14,737,555 15,069,150

0000000000

1,140,001 1,165,651 1,191,878 1,218,696 1,246,116 1,274,154 1,302,822 1,332,136 1,362,109 1,392,7561,928,452 1,967,021 2,006,361 2,046,488 2,087,418 2,129,166 2,171,750 2,215,185 2,259,488 2,304,678

105,128,731 105,573,194 106,060,479 106,591,658 107,167,830 107,790,124 108,459,697 109,177,735 109,945,456 110,764,109

9.87 9.92 9.96 10.01 10.07 10.12 10.19 10.25 10.33 10.40

12,221,487 11,450,066 10,731,480 10,061,922 9,437,867 8,856,051 8,313,449 7,807,259 7,334,888 6,893,932

1,367,964,978 1,379,415,044 1,390,146,525 1,400,208,447 1,409,646,314 1,418,502,365 1,426,815,814 1,434,623,073 1,441,957,962 1,448,851,893

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB Coal

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operating Year 1 2 3 4 5 6 7 8 9 10 11 

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fuel Prices ($/mmBtu)

PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 

Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1Variable O&M Calculations

Consumption Rates

Lime (tons) 00000000000

Limestone (tons) 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 70,848 76,183 75,379 7

Total Water Requirement (1000s ga 1,002,642 992,065 1,033,415 1,034,896 968,052 971,123 867,471 896,086 932,434 1,002,642 992,065 1,033

Waste Ash Disposal (tons) 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 136,900 147,208 145,655 15

Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 1Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 Bag Cost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 1

Total Water Requirement, $/1000 gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 

Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0 Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1Capacity Factor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76

Annual Generation (MWh) 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347Aux. Power (MWh) 212,634 210,391 219,160 219,474 205,298 205,950 183,968 190,037 197,745 212,634 210,391 21Aux. Power Cost ($/MWh) 66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 1

Fuel Price ($/mmBtu) 2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3

Fuel Consumption (mmBtu/year) 00000000000

Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis 118,650,750 113,238,091 107,166,911 101,103,611 95,048,429 89,001,607 82,963,397 78,714,723 76,921,527 75,803,729 74,695,622 73,597

Fixed O&M 8,621,899 8,794,337 8,970,224 9,149,629 9,332,621 9,519,274 9,709,659 9,903,852 10,101,929 10,303,968 10,510,047 10,720Fuel 00000000000Aux Power Purchase 14,033,566 13,658,532 14,159,288 14,807,532 14,126,768 15,666,312 15,470,214 17,666,049 18,984,202 21,081,658 21,541,895 23,174

Bag Replacement 00000000000Lime 00000000000Limestone 3,196,265 3,225,800 3,427,458 3,501,015 3,340,382 3,417,998 3,114,248 3,281,316 3,482,703 3,819,833 3,855,129 4,09Total Water Requirement 737,810 746,453 795,060 814,114 778,665 798,710 729,514 770,534 819,829 901,393 911,952 97Waste Ash Disposal 1,393,942 1,406,823 1,494,769 1,526,848 1,456,794 1,490,643 1,358,173 1,431,034 1,518,862 1,665,890 1,681,283 1,78

Total Revenue Requirements 146,634,232 141,070,036 136,013,711 130,902,749 124,083,659 119,894,544 113,345,205 111,767,509 111,829,053 113,576,471 113,195,930 114,345

Busbar Electricity Price ($/MWh) 13.32 12.95 11.99 11.52 11.67 11.24 11.90 11.36 10.92 10.32 10.39 

Levelized ($/MWh) 11.27

Present Value (PVRR) 136,800,306 122,782,981 110,442,895 99,164,348 87,694,646 79,051,408 69,721,230 64,140,030 59,871,471 56,729,029 52,747,210 49,709

Cumulative PVRR 136,800,306 259,583,287 370,026,182 469,190,529 556,885,176 635,936,584 705,657,814 769,797,843 829,669,314 886,398,343 939,145,553 988,855Net Present Value = 1,571,524,323

Levelized ($/year) 120,467,303

5.11 $/kW-yr fixed

1.76 $/MWH variable

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 11.27

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,571,524,323

Levelized ($/year) 120,467,303

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 

16 17 18 19 20 21 22 23 24 25 26 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 

1.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1

00000000000

65,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 7

867,471 896,086 932,434 1,002,642 992,065 1,033,415 1,034,896 968,052 971,123 867,471 896,086 96127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 14

166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 2

56.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 

163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 2

1.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 

12.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.00.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7

1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1

64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72

9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646

183,968 190,037 197,745 212,634 210,391 219,160 219,474 205,298 205,950 183,968 190,037 20

116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 13.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4

00000000000

0.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

69,310,963 68,267,431 67,235,820 66,216,487 65,209,800 64,216,139 63,235,895 62,269,469 61,317,277 60,379,746 59,457,315 58,550

11,603,942 11,836,020 12,072,741 12,314,196 12,560,479 12,811,689 13,067,923 13,329,281 13,595,867 13,867,784 14,145,140 14,428

00000000000

21,476,234 22,683,818 24,135,021 26,536,201 26,847,046 28,595,283 29,280,558 28,005,586 28,726,553 26,237,834 27,713,157 30,659

0000000000000000000000

3,721,814 3,921,476 4,162,152 4,565,054 4,607,236 4,895,254 5,000,311 4,770,888 4,881,743 4,447,913 4,686,527 5,172

891,258 941,373 1,001,597 1,101,246 1,114,146 1,186,697 1,215,136 1,162,225 1,192,145 1,088,863 1,150,089 1,272

1,623,143 1,710,218 1,815,181 1,990,893 2,009,289 2,134,898 2,180,716 2,080,660 2,129,006 1,939,806 2,043,869 2,255

108,627,354 109,360,337 110,422,513 112,724,075 112,347,997 113,839,961 113,980,539 111,618,110 111,842,591 107,961,946 109,196,098 112,338

11.40 11.11 10.78 10.24 10.31 10.03 10.03 10.50 10.49 11.33 11.10 

35,773,907 33,599,956 31,651,055 30,143,866 28,028,464 26,496,005 24,749,593 22,611,206 21,137,225 19,035,450 17,961,858 17,239

1,153,054,690 1,186,654,646 1,218,305,701 1,248,449,566 1,276,478,030 1,302,974,035 1,327,723,629 1,350,334,834 1,371,472,059 1,390,507,510 1,408,469,368 1,425,708

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 11.27

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,571,524,323

Levelized ($/year) 120,467,303

2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

31 32 33 34 35 36 37 38 39 40

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.67

2.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.6554

0000000000

73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668

969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348

232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.12

76.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82

219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.91

1.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.75

17.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.50

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%

2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.4379

72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%

10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554

205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615

162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.6742

0000000000

0.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.0622

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

55,088,006 54,266,181 53,462,928 52,678,803 51,914,381 51,170,252 50,447,026 49,745,329 49,065,808 48,409,12815,617,378 15,929,725 16,248,320 16,573,286 16,904,752 17,242,847 17,587,704 17,939,458 18,298,247 18,664,212

0000000000

33,513,490 34,267,544 35,038,563 35,826,931 36,633,037 37,457,280 38,300,069 39,161,821 40,042,962 40,943,928

00000000000000000000

5,598,466 5,710,435 5,824,644 5,941,137 6,059,960 6,181,159 6,304,782 6,430,878 6,559,495 6,690,6851,390,801 1,422,094 1,454,091 1,486,809 1,520,262 1,554,468 1,589,443 1,625,206 1,661,773 1,699,1632,441,580 2,490,412 2,540,220 2,591,025 2,642,845 2,695,702 2,749,616 2,804,608 2,860,700 2,917,914

113,649,722 114,086,391 114,568,766 115,097,990 115,675,236 116,301,708 116,978,640 117,707,300 118,488,985 119,325,031

10.67 10.72 10.76 10.81 10.87 10.92 10.99 11.06 11.13 11.21

13,212,075 12,373,375 11,592,371 10,864,894 10,187,083 9,555,364 8,966,427 8,417,205 7,904,860 7,426,762

1,484,235,983 1,496,609,358 1,508,201,729 1,519,066,623 1,529,253,705 1,538,809,069 1,547,775,496 1,556,192,701 1,564,097,562 1,571,524,323

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB Coal

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operating Year 1 2 3 4 5 6 7 8 9 10 11 

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fuel Prices ($/mmBtu)

PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 

Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1Variable O&M Calculations

Consumption Rates

Lime (tons) 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 51,007 54,848 54,269 5

Limestone (tons) 00000000000

Total Water Requirement (1000s ga 829,489 820,739 854,948 856,173 800,873 803,413 717,662 741,336 771,406 829,489 820,739 85

Waste Ash Disposal (tons) 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 108,129 116,270 115,044 11

Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 1Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 Bag Cost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 1

Total Water Requirement, $/1000 gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 

Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0 Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1Capacity Factor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76

Annual Generation (MWh) 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347Aux. Power (MWh) 153,931 152,308 158,656 158,883 148,621 149,092 133,179 137,572 143,153 153,931 152,308 15Aux. Power Cost ($/MWh) 66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 1

Fuel Price ($/mmBtu) 2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3

Fuel Consumption (mmBtu/year) 00000000000

Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis 110,775,269 105,721,877 100,053,673 94,392,827 88,739,559 83,094,097 77,456,675 73,490,009 71,815,837 70,772,232 69,737,677 68,712

Fixed O&M 7,264,874 7,410,171 7,558,375 7,709,542 7,863,733 8,021,008 8,181,428 8,345,056 8,511,958 8,682,197 8,855,841 9,032Fuel 00000000000Aux Power Purchase 10,159,269 9,887,772 10,250,282 10,719,563 10,226,740 11,341,256 11,199,296 12,788,919 13,743,164 15,261,569 15,594,746 16,77

Bag Replacement 1,861,546 1,878,748 1,996,196 2,039,037 1,945,482 1,990,687 1,813,779 1,911,081 2,028,372 2,224,720 2,245,278 2,385Lime 6,543,322 6,619,971 7,051,053 7,220,029 6,905,645 7,083,421 6,469,751 6,833,537 7,270,715 7,994,074 8,087,716 8,614Limestone 00000000000Total Water Requirement 610,393 617,543 657,756 673,519 644,192 660,776 603,530 637,466 678,248 745,726 754,461 80Waste Ash Disposal 1,100,988 1,111,161 1,180,625 1,205,962 1,150,630 1,177,366 1,072,736 1,130,284 1,199,654 1,315,782 1,327,941 1,41

Total Revenue Requirements 138,315,660 133,247,243 128,747,960 123,960,479 117,475,982 113,368,611 106,797,194 105,136,353 105,247,947 106,996,300 106,603,660 107,736

Busbar Electricity Price ($/MWh) 12.56 12.23 11.35 10.91 11.05 10.63 11.21 10.68 10.28 9.72 9.79 

Levelized ($/MWh) 10.64

Present Value (PVRR) 129,039,613 115,974,265 104,543,119 93,905,286 83,024,749 74,748,592 65,693,398 60,334,607 56,348,053 53,442,374 49,675,334 46,836

Cumulative PVRR 129,039,613 245,013,878 349,556,997 443,462,282 526,487,032 601,235,623 666,929,022 727,263,629 783,611,682 837,054,056 886,729,390 933,565Net Present Value = 1,483,331,874

Levelized ($/year) 113,706,792

4.30 $/kW-yr fixed

1.84 $/MWH variable

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.64

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,483,331,874

Levelized ($/year) 113,706,792

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 

16 17 18 19 20 21 22 23 24 25 26 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 

1.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 147,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 5

00000000000

717,662 741,336 771,406 829,489 820,739 854,948 856,173 800,873 803,413 717,662 741,336 80100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 11

166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 2

56.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 

163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 2

1.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 

12.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.00.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7

1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1

64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72

9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646

133,179 137,572 143,153 153,931 152,308 158,656 158,883 148,621 149,092 133,179 137,572 14

116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 13.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4

00000000000

0.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

64,710,426 63,736,159 62,773,021 61,821,347 60,881,479 59,953,773 59,038,592 58,136,314 57,247,324 56,372,021 55,510,817 54,664

9,777,564 9,973,115 10,172,577 10,376,029 10,583,549 10,795,220 11,011,125 11,231,347 11,455,974 11,685,094 11,918,795 12,157

00000000000

15,547,212 16,421,414 17,471,979 19,210,256 19,435,285 20,700,880 21,196,969 20,273,983 20,795,909 18,994,260 20,062,286 22,195

2,167,633 2,283,919 2,424,092 2,658,747 2,683,315 2,851,060 2,912,247 2,778,627 2,843,191 2,590,522 2,729,495 3,0127,904,190 8,348,634 8,882,740 9,766,479 9,880,883 10,524,311 10,776,522 10,307,276 10,572,624 9,656,667 10,199,650 11,284

00000000000

737,341 778,801 828,625 911,065 921,737 981,759 1,005,286 961,513 986,266 900,821 951,473 1,052

1,282,019 1,350,794 1,433,698 1,572,482 1,587,012 1,686,223 1,722,411 1,643,383 1,681,569 1,532,131 1,614,324 1,78

102,126,385 102,892,837 103,986,732 106,316,403 105,973,260 107,493,225 107,663,151 105,332,444 105,582,856 101,731,516 102,986,840 106,147

10.72 10.46 10.16 9.66 9.73 9.47 9.47 9.91 9.90 10.68 10.47 

33,632,963 31,612,876 29,806,329 28,430,372 26,438,101 25,018,816 23,377,843 21,337,877 19,954,193 17,936,924 16,940,487 16,289

1,088,131,343 1,119,744,219 1,149,550,548 1,177,980,920 1,204,419,021 1,229,437,837 1,252,815,681 1,274,153,558 1,294,107,751 1,312,044,675 1,328,985,162 1,345,274

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 10.64

Present Value (PVRR)

Cumulative PVRRNet Present Value = 1,483,331,874

Levelized ($/year) 113,706,792

2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

31 32 33 34 35 36 37 38 39 40

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.67

2.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.655453,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037

0000000000

802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432

232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.12

76.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82

219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.91

1.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.75

17.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.50

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%

2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.4379

72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%

10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554

148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850

162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.6742

0000000000

0.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.0622

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

51,431,522 50,664,246 49,914,309 49,182,231 48,468,547 47,773,810 47,098,589 46,443,468 45,809,050 45,195,95713,159,313 13,422,500 13,690,950 13,964,768 14,244,064 14,528,945 14,819,524 15,115,915 15,418,233 15,726,597

0000000000

24,261,300 24,807,179 25,365,340 25,936,060 26,519,622 27,116,313 27,726,430 28,350,275 28,988,156 29,640,390

3,260,620 3,325,832 3,392,349 3,460,196 3,529,400 3,599,988 3,671,987 3,745,427 3,820,336 3,896,742

12,334,425 12,611,950 12,895,719 13,185,872 13,482,555 13,785,912 14,096,095 14,413,257 14,737,555 15,069,150

0000000000

1,150,615 1,176,504 1,202,975 1,230,042 1,257,718 1,286,017 1,314,952 1,344,539 1,374,791 1,405,7231,928,452 1,967,021 2,006,361 2,046,488 2,087,418 2,129,166 2,171,750 2,215,185 2,259,488 2,304,678

107,526,247 107,975,231 108,468,003 109,005,658 109,589,323 110,220,152 110,899,327 111,628,065 112,407,609 113,239,239

10.10 10.14 10.19 10.24 10.29 10.35 10.42 10.48 10.56 10.64

12,500,205 11,710,582 10,975,080 10,289,796 9,651,119 9,055,702 8,500,447 7,982,482 7,499,148 7,047,983

1,400,619,534 1,412,330,116 1,423,305,196 1,433,594,992 1,443,246,112 1,452,301,814 1,460,802,261 1,468,784,742 1,476,283,890 1,483,331,874

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB Coal

Calendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Operating Year 1 2 3 4 5 6 7 8 9 10 11 

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fuel Prices ($/mmBtu)

PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 

Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1Variable O&M Calculations

Consumption Rates

Lime (tons) 00000000000

Limestone (tons) 483,319 478,220 498,153 498,867 466,645 468,125 418,161 431,954 449,475 483,319 478,220 49

Total Water Requirement (1000s ga 1,033,120 1,022,222 1,064,829 1,066,354 997,479 1,000,643 893,841 923,326 960,778 1,033,120 1,022,222 1,064

Waste Ash Disposal (tons) 942,733 932,788 971,667 973,059 910,209 913,097 815,639 842,544 876,720 942,733 932,788 97

Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 1Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 Bag Cost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 1

Total Water Requirement, $/1000 gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 

Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0 Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.0

Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1Capacity Factor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76

Annual Generation (MWh) 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347Aux. Power (MWh) 263,510 260,730 271,598 271,987 254,419 255,226 227,985 235,505 245,058 263,510 260,730 27Aux. Power Cost ($/MWh) 66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 1

Fuel Price ($/mmBtu) 2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3

Fuel Consumption (mmBtu/year) 00000000000

Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis 125,134,966 119,426,508 113,023,540 106,628,884 100,242,788 93,865,510 87,497,314 83,016,452 81,125,259 79,946,372 78,777,708 77,61

Fixed O&M 8,984,524 9,164,214 9,347,499 9,534,449 9,725,137 9,919,640 10,118,033 10,320,394 10,526,802 10,737,338 10,952,084 11,17Fuel 00000000000Aux Power Purchase 17,391,290 16,926,524 17,547,093 18,350,438 17,506,793 19,414,693 19,171,676 21,892,895 23,526,434 26,125,736 26,696,091 28,71

Bag Replacement 00000000000Lime 00000000000Limestone 20,277,675 20,465,048 21,744,405 22,211,062 21,191,978 21,684,389 19,757,342 20,817,252 22,094,887 24,233,698 24,457,627 25,986Total Water Requirement 760,238 769,143 819,229 838,861 802,335 822,990 751,690 793,957 844,750 928,794 939,674 1,00Waste Ash Disposal 8,926,919 9,009,407 9,572,623 9,778,062 9,329,427 9,546,203 8,697,851 9,164,459 9,726,918 10,668,495 10,767,076 11,440

Total Revenue Requirements 181,475,613 175,760,846 172,054,388 167,341,756 158,798,457 155,253,424 145,993,906 146,005,409 147,845,049 152,640,434 152,590,260 155,937

Busbar Electricity Price ($/MWh) 16.48 16.13 15.16 14.73 14.94 14.56 15.33 14.84 14.44 13.86 14.01 

Levelized ($/MWh) 15.05

Present Value (PVRR) 169,305,072 152,976,785 139,707,863 126,768,431 112,228,916 102,364,973 89,804,193 83,788,136 79,153,855 76,240,647 71,104,239 67,790

Cumulative PVRR 169,305,072 322,281,857 461,989,720 588,758,151 700,987,067 803,352,040 893,156,234 976,944,370 1,056,098,225 1,132,338,872 1,203,443,111 1,271,233Net Present Value = 2,098,266,524

Levelized ($/year) 160,845,432

5.32 $/kW-yr fixed

4.30 $/MWH variable

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 15.05

Present Value (PVRR)

Cumulative PVRRNet Present Value = 2,098,266,524

Levelized ($/year) 160,845,432

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 

16 17 18 19 20 21 22 23 24 25 26 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 

1.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1

00000000000

418,161 431,954 449,475 483,319 478,220 498,153 498,867 466,645 468,125 418,161 431,954 46893,841 923,326 960,778 1,033,120 1,022,222 1,064,829 1,066,354 997,479 1,000,643 893,841 923,326 99815,639 842,544 876,720 942,733 932,788 971,667 973,059 910,209 913,097 815,639 842,544 91

166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 2

56.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 

163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 2

1.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 

12.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.00.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.0

8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7

1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1

64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72

9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646

227,985 235,505 245,058 263,510 260,730 271,598 271,987 254,419 255,226 227,985 235,505 25

116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 13.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4

00000000000

0.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 

73,098,780 71,998,220 70,910,231 69,835,192 68,773,490 67,725,526 66,691,712 65,672,471 64,668,243 63,679,475 62,706,634 61,75012,091,986 12,333,826 12,580,502 12,832,112 13,088,755 13,350,530 13,617,540 13,889,891 14,167,689 14,451,043 14,740,064 15,034

00000000000

26,614,720 28,111,235 29,909,658 32,885,353 33,270,572 35,437,099 36,286,336 34,706,309 35,599,777 32,515,598 34,343,913 37,995

0000000000000000000000

23,611,853 24,878,543 26,405,435 28,961,513 29,229,128 31,056,364 31,722,866 30,267,363 30,970,647 28,218,350 29,732,162 32,812

918,351 969,989 1,032,044 1,134,721 1,148,014 1,222,770 1,252,074 1,197,554 1,228,384 1,121,963 1,185,050 1,31

10,394,737 10,952,377 11,624,567 12,749,839 12,867,652 13,672,063 13,965,480 13,324,718 13,634,328 12,422,673 13,089,105 14,445

146,730,426 149,244,189 152,462,438 158,398,731 158,377,611 162,464,353 163,536,008 159,058,307 160,269,067 152,409,102 155,796,927 163,349

15.40 15.17 14.89 14.39 14.54 14.32 14.39 14.96 15.03 16.00 15.83 

48,322,272 45,853,902 43,701,206 42,357,855 39,511,885 37,813,227 35,510,007 32,221,475 30,289,386 26,872,208 25,627,311 25,067

1,495,181,809 1,541,035,711 1,584,736,917 1,627,094,773 1,666,606,658 1,704,419,885 1,739,929,892 1,772,151,367 1,802,440,752 1,829,312,961 1,854,940,272 1,880,007

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004
WHITE BLUFF STATION UNITS 1 AND 2

EVALUATION OF WET VS. DRY FGD TECHNOLOGIES

Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB Coal

Calendar Year

Operating Year

Annual Factors and Prices:

Input AssumptionsTax Depreciation

7-Year Amort.

Fuel Prices ($/mmBtu)

PRB Coal

Inflation FactorsVariable O&M Calculations

Consumption Rates

Lime (tons)

Limestone (tons)Total Water Requirement (1000s ga

Waste Ash Disposal (tons)

Lime, $/tonLimestone $/tonBag Cost, $

Total Water Requirement, $/1000 gal

Waste Ash Disposal, $/tonCalculated ValuesTax Depreciation Adjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacity Factor

Annual Generation (MWh)Aux. Power (MWh)Aux. Power Cost ($/MWh)Fuel Price ($/mmBtu)Fuel Consumption (mmBtu/year)Present Value FactorEvaluation Period Factor

Annual Revenue Requirements:

Expense Totals

Fixed Charges Basis Fixed O&MFuel 

Aux Power Purchase

Bag ReplacementLimeLimestoneTotal Water RequirementWaste Ash Disposal

Total Revenue Requirements

Busbar Electricity Price ($/MWh)

Levelized ($/MWh) 15.05

Present Value (PVRR)

Cumulative PVRRNet Present Value = 2,098,266,524

Levelized ($/year) 160,845,432

2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

31 32 33 34 35 36 37 38 39 40

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.67

2.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.6554

0000000000

467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611

232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.12

76.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82

219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.91

1.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.75

17.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.50

0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%

7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%

2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.4379

72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%

10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554

254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811

162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.6742

0000000000

0.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.0622

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

58,098,544 57,231,807 56,384,656 55,557,679 54,751,481 53,966,686 53,203,936 52,463,892 51,747,236 51,054,66816,274,221 16,599,706 16,931,700 17,270,334 17,615,740 17,968,055 18,327,416 18,693,965 19,067,844 19,449,201

0000000000

41,532,055 42,466,526 43,422,023 44,399,019 45,397,997 46,419,452 47,463,889 48,531,827 49,623,793 50,740,328

00000000000000000000

35,517,666 36,228,019 36,952,580 37,691,631 38,445,464 39,214,373 39,998,661 40,798,634 41,614,607 42,446,899

1,433,079 1,465,323 1,498,293 1,532,005 1,566,475 1,601,721 1,637,759 1,674,609 1,712,288 1,750,814

15,636,080 15,948,801 16,267,777 16,593,133 16,924,995 17,263,495 17,608,765 17,960,941 18,320,159 18,686,563

168,491,645 169,940,183 171,457,029 173,043,800 174,702,152 176,433,782 178,240,427 180,123,867 182,085,926 184,128,472

15.83 15.96 16.10 16.25 16.41 16.57 16.74 16.92 17.10 17.29

19,587,590 18,431,065 17,348,476 16,334,798 15,385,361 14,495,823 13,662,150 12,880,591 12,147,659 11,460,112

1,966,120,488 1,984,551,553 2,001,900,029 2,018,234,828 2,033,620,189 2,048,116,012 2,061,778,161 2,074,658,752 2,086,806,412 2,098,266,524

ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004